Virginia regulators seek suggestions on saving energy

Ottawa Hydro Substation Heritage Designation highlights Hydro Ottawa's 1920s architecture, Art Deco facades, and municipal utility history, protecting key voltage-reduction sites in Glebe, Carling-Merivale, Holland, King Edward, and Old Ottawa South.

Key Points

A city plan to protect Hydro Ottawa's 1920s substations for architecture, utility role, and civic electrical heritage.

✅ Protects five operating voltage-reduction sites citywide

✅ Recognizes Art Deco and early 20th century utility architecture

✅ Allows emergency demolition to ensure grid safety

The city of Ottawa is looking to designate five hydro substations built nearly a century ago as heritage structures, a move intended to protect the architectural history of Ottawa's earliest forays into the electricity business, even as Ottawa electricity consumption has shifted in recent years.

All five buildings are still used by Hydro Ottawa to reduce the voltage coming from transmission lines before the electricity is transmitted to homes and businesses, and when severe weather causes outages, Sudbury Hydro crews work to reconnect service across communities.

Electricity came to Ottawa in 1882 when two carbon lamps were installed on LeBreton Flats, heritage planner Anne Fitzpatrick told the city's built heritage subcommittee on Tuesday. It became a lucrative business, and soon a privately owned monopoly that drew public scrutiny similar to debates over retroactive charges in neighboring jurisdictions.

In 1905, city council held a special meeting to buy the electrical company, which led to a dramatic drop in electricity rates for residents, a contrast with recent discussions about peak hydro rates for self-isolating customers.

The substations are now owned by Hydro Ottawa, which agreed to the heritage designations on the condition it not be prevented from emergency demolitions if it needs to address incidents such as damaging storms in Ontario while it works to "preserve public safety and the continuity of critical hydro electrical services."

Built in 1922, the substation at the intersection of Glebe and Bronson avenues was the first to be built by the new municipal electrical department, long before modern battery storage projects became commonplace on Ontario's grid.

The largest of the substations being protected dates back to 1929 and is found at the corner of Carling Avenue and Merivale Road. It was built to accommodate a growing population in areas west of downtown including Hintonburg and Mechanicsville.

The substation on Holland Avenue near the Queensway is different from the others because it was built in 1924 to serve the Ottawa Electric Railway Company. The streetcar company operated from 1891 to 1959, and urban electrical infrastructure can face failures such as the Hydro-Québec manhole fire that left thousands without power.

This substation on King Edward Avenue was built in 1931 and designed by architect William Beattie, who also designed York Street Public School in Lowertown and the substation on Carling Avenue. 

The last substation to be built in a 'bold and decorative style' is at 39 Riverdale Ave. in Old Ottawa South, according to city staff. It was designed in an Art Deco style by prominent architect J. Albert Ewart, who was also behind the Civic Hospital and nearby Southminster Church on Bank Street.

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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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New Zealand Energy Transition will electrify transport and industry with renewables, grid-scale solar, wind farms, geothermal, batteries, demand response, pumped hydro, and transmission upgrades to manage dry-year risk and winter peak loads.

Key Points

A shift to renewables and smart demand to decarbonise transport and industry while ensuring reliable, affordable power.

✅ Electrifies transport and industrial heat with renewables

✅ Uses demand response, batteries, and pumped hydro for resilience

✅ Targets 99%+ renewable supply, managing dry-year and peak loads

As fossil fuels are phased out over the coming decades, the Climate Change Commission (CCC) suggests electricity will take up much of the slack, aligning with the vision of a sustainable electric planet powering our vehicle fleet and replacing coal and gas in industrial processes.

But can the electricity system really provide for this increased load where and when it is needed? The answer is “yes”, with some caveats.

Our research examines climate change impacts on the New Zealand energy system. It shows we’ll need to pay close attention to demand as well as supply. And we’ll have to factor in the impacts of climate change when we plan for growth in the energy sector.

Demand for electricity to grow
While electricity use has not increased in NZ in the past decade, many agencies project steeply rising demand in coming years. This is partly due to both increasing population and gross domestic product, but mostly due to the anticipated electrification of transport and industry, which could result in a doubling of demand by mid-century.

It’s hard to get a sense of the scale of the new generation required, but if wind was the sole technology employed to meet demand by 2050, between 10 and 60 new wind farms would be needed nationwide.

Of course, we won’t only build wind farms, as renewables are coming on strong and grid-scale solar, rooftop solar, new geothermal, some new small hydro plant and possibly tidal and wave power will all have a part to play.

Managing the demand
As well as providing more electricity supply, demand management and batteries will also be important. Our modelling shows peak demand (which usually occurs when everyone turns on their heaters and ovens at 6pm in winter) could be up to 40% higher by 2050 than it is now.

But meeting this daily period of high demand could see expensive plant sitting idle for much of the time (with the last 25% of generation capacity only used about 10% of the time).

This is particularly a problem in a renewable electricity system when the hydro lakes are dry, as hydro is one of the few renewable electricity sources that can be stored during the day (as water behind the dam) and used over the evening peak (by generating with that stored water).

Demand response will therefore be needed. For example, this might involve an industrial plant turning off when there is too much load on the electricity grid.

But by 2050, a significant number of households will also need smart appliances and meters that automatically use cheaper electricity at non-peak times. For example, washing machines and electric car chargers could run automatically at 2am, rather than 6pm when demand is high.

Our modelling shows a well set up demand response system could mitigate dry-year risk (when hydro lakes are low on water) in coming decades, where currently gas and coal generation is often used.

Instead of (or as well as) having demand response and battery systems to combat dry-year risk, a pumped storage system could be built. This is where water is pumped uphill when hydro lake inflows are plentiful, and used to generate electricity during dry periods.

The NZ Battery project is currently considering the potential for this in New Zealand, and debates such as whether we would use Site C's electricity offer relevant lessons.

Almost (but not quite) 100% renewable
Dry-year risk would be greatly reduced and there would be “greater greenhouse gas emissions savings” if the Interim Climate Change Committee’s (ICCC) 2019 recommendation to aim for 99% renewable electricity was adopted, rather than aiming for 100%.

A small amount of gas-peaking plant would therefore be retained. The ICCC said going from 99% to 100% renewable electricity by overbuilding would only avoid a very small amount of carbon emissions, at a very high cost.

Our modelling supports this view. The CCC’s draft advice on the issue also makes the point that, although 100% renewable electricity is the “desired end point”, timing is important to enable a smooth transition.

Despite these views, Energy Minister Megan Woods has said the government will be keeping the target of a 100% renewable electricity sector by 2030.

Impacts of climate change
In future, the electricity system will have to respond to changing climate patterns as well, becoming resilient to climate risks over time.

The National Institute of Water and Atmospheric Research predicts winds will increase in the South Island and decrease in the far north in coming decades.

Inflows to the biggest hydro lakes will get wetter (more rain in their headwaters), and their seasonality will change due to changes in the amount of snow in these catchments.

Our modelling shows the electricity system can adapt to those changing conditions. One good news story (unless you’re a skier) is that warmer temperatures will mean less snow storage at lower elevations, and therefore higher lake inflows in the big hydro catchments in winter, leading to a better match between times of high electricity demand and higher inflows.

The price is right
The modelling also shows the cost of generating electricity is not likely to increase, because the price of building new sources of renewable energy continues to fall globally.

Because the cost of building new renewables is now cheaper than non-renewables (such as coal-fired plants), investing in carbon-free electricity is increasingly compelling, and renewables are more likely to be built to meet new demand in the near term.

While New Zealand’s electricity system can enable the rapid decarbonisation of (at least) our transport and industrial heat sectors, international efforts like cleaning up Canada's electricity underline the need for certainty so the electricity industry can start building to meet demand everywhere.

Bipartisan cooperation at government level will be important to encourage significant investment in generation and transmission projects with long lead times and life expectancies, as analyses of climate policy and grid implications underscore in comparable markets.

Infrastructure and markets are needed to support demand response uptake, as well as certainty around the Tiwai exit in 2024 and whether pumped storage is likely to be built.

Our electricity system can support the rapid decarbonisation needed if New Zealand is to do its fair share globally to tackle climate change.

But sound planning, firm decisions and a supportive and relatively stable regulatory framework are all required before shovels can hit the ground.

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B.C. LNG Electrification embeds clean hydro and wind power into low-emission liquefied natural gas, cutting carbon intensity, enabling coal displacement in Asia, and opening grid-scale demand for independent power producers and ITMO-based climate accounting.

Key Points

Powering LNG with clean electricity cuts carbon intensity, displaces coal, and grows demand for B.C.'s clean power.

✅ Electric-drive LNG cuts emissions intensity by up to 80%.

✅ Creates major grid load, boosting B.C. independent power producers.

✅ Enables ITMO crediting when coal displacement is verified.

B.C. has abundant clean power – if only there was a way to ship those electrons across the sea to help coal-dependent countries reduce their emissions, and even regionally, Alberta–B.C. grid link benefits could help move surplus power domestically.

Natural gas that is liquefied using clean hydro and wind power and then exported would be, in a sense, a way of embedding B.C.’s low emission electricity in another form of energy, and, alongside the Canada–Germany clean energy pact, part of a broader export strategy.

Given the increased demand that could come from an LNG industry – especially one that moves towards greater electrification and, as the IEA net-zero electricity report notes, broader system demand – poses some potentially big opportunities for B.C.’s clean energy independent power sector, as those attending the Clean Energy Association of BC's annual at the Generate conference heard recently.

At a session on LNG electrification, delegates were told that LNG produced in B.C. with electricity could have some significant environmental benefits.

Given how much power an LNG plant that uses electric drive consumes, an electrified LNG industry could also pose some significant opportunities for independent power producers – a sector that had the wind taken out of its sails with the sanctioning of the Site C dam project.

Only one LNG plant being built in B.C. – Woodfibre LNG – will use electric drive to produce LNG, although the companies behind Kitimat LNG have changed their original design plans, and now plan to use electric drive drive as well.

Even small LNG plants that use electric drive require a lot of power.

“We’re talking about a lot of power, since it’s one of the biggest consumers you can connect to a grid,” said Sven Demmig, head of project development for Siemens.

Most LNG plants still burn natural gas to drive the liquefaction process – a choice that intersects with climate policy and electricity grids in Canada. They typically generate 0.35 tonnes of CO2e per tonne of LNG produced.

Because it will use electric drive, LNG produced by Woodfibre LNG will have an emissions intensity that is 80% less than LNG produced in the Gulf of Mexico, said Woodfibre president David Keane.

In B.C., the benchmark for GHG intensities for LNG plants has been set at 0.16 tonnes of CO2e per tonne of LNG. Above that, LNG producers would need to pay higher carbon taxes than those that are below the benchmark.

The LNG Canada plant has an intensity of 0.15 tonnes og CO2e per tonne of LNG. Woodfibre LNG will have an emissions intensity of just 0.059, thanks to electric drive.

“So we will be significantly less than any operating facility in the world,” Keane said.

Keane said Sinopec has recently estimated that it expects China’s demand for natural gas to grow by 82% by 2030.

“So China will, in fact, get its gas supply,” Keane said. “The question is: where will that supply come from?

“For every tonne of LNG that’s being produced today in the United States -- and tonne of LNG that we’re not producing in Canada -- we’re seeing about 10 million tonnes of carbon leakage every single year.”

The first Canadian company to produce LNG that ended up in China is FortisBC. Small independent operators have been buying LNG from FortisBC’s Tilbury Island plant and shipping to China in ISO containers on container ships.

David Bennett, director of communications for FortisBC, said those shipments are traced to industries in China that are, indeed, using LNG instead of coal power now.

“We know where those shipping containers are going,” he said. “They’re actually going to displace coal in factories in China.”

Verifying what the LNG is used for is important, if Canadian producers want to claim any kind of climate credit. LNG shipped to Japan or South Korea to displace nuclear power, for example, would actually result in a net increase in GHGs. But used to displace coal, the emissions reductions can be significant, since natural gas produces about half the CO2 that coal does.

The problem for LNG producers here is B.C.’s emissions reduction targets as they stand today. Even LNG produced with electricity will produce some GHGs. The fact that LNG that could dramatically reduce GHGs in other countries, if it displaces coal power, does not count in B.C.’s carbon accounting.

Under the Paris Agreement, countries agree to set their own reduction targets, and, for Canada, cleaning up Canada’s electricity remains critical to meeting climate pledges, but don’t typically get to claim any reductions that might result outside their own country.

Canada is exploring the use of Internationally Transferred Mitigation Outcomes (ITMO) under the Under the Paris Agreement to allow Canada to claim some of the GHG reductions that result in other countries, like China, through the export of Canadian LNG.

“For example, if I were producing 4 million tonnes of greenhouse gas emissions in B.C. and I was selling 100% of my LNG to China, and I can verify that they’re replacing coal…they would have a reduction of about 60 or million tonnes of greenhouse gas emissions,” Keane said.

“So if they’re buying 4 million tonnes of emissions from us, under these ITMOs, then they have net reduction of 56 million tonnes, we’d have a net increase of zero.”

But even if China and Canada agreed to such a trading arrangement, the United Nations still hasn’t decided just how the rules around ITMOs will work.

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Texas Power Grid Reliability faces record peak demand as ERCOT balances renewable energy, wind and solar variability, gas-fired generation, demand response, and transmission limits to prevent blackouts during heat waves and extreme weather.

Key Points

Texas Power Grid Reliability is ERCOT's capacity to meet peak demand with diverse resources while limiting outages.

✅ Record heat drives peak demand across ERCOT.

✅ Variable wind/solar need firm, flexible capacity.

✅ Demand response and reserves reduce blackout risk.

The electric power grid in Texas, which collapsed dramatically during the 2021 winter storm across the state, is being tested again as the state suffers unusually hot summer weather. Demand for electricity has reached new records at a time of rapid change in the mix of power sources as wind and solar ramp up. That’s feeding a debate about the dependability of the state’s power. 

1. Why is the Texas grid under threat again? 

Already the biggest power user in the nation, electricity use in the second most-populous state surged to record levels during heat waves this summer. The jump in demand comes as the state becomes more dependent on intermittent renewable power sources, raising concerns among some critics that more reliance on wind and solar will leave the grid more vulnerable to disruption. Green sources will produce almost 40% of the power in Texas this year, US Energy Information Administration data show. While that trails California’s 52%, Texas is a bigger market. It’s already No. 1 in wind, making it the largest clean energy market in the US. 

2. How is Texas unique? 

The spirit of defiance of the Lone Star State extends to its power grid as well. The Electric Reliability Council of Texas, or Ercot as the grid operator is known, serves about 90% of the state’s electricity needs and has very few high-voltage transmission lines connecting to nearby grids. It’s a deliberate move to avoid federal oversight of the power market. That means Texas has to be mainly self-reliant and cannot depend on neighbors during extreme conditions. That vulnerability is a dramatic twist for a state that’s also the energy capital of the US, thanks to vast oil and natural gas producing fields. Favorable regulations are also driving a wind and solar boom in Texas. 

3. Why the worry? 

The summer of 2023 will mark the first time all of the state’s needs cannot be met by traditional power plants, like nuclear, coal and gas. A sign of potential trouble came on June 20 when state officials urged residents to conserve power because of low supplies from wind farms and unexpected closures of fossil-fuel generators amid supply-chain constraints that limited availability. As of late July, the grid was holding up, thanks to the help of renewable sources. Solar generation has been coming in close to expected summer capacity, or exceeding it on most days. This has helped offset the hours in the middle of the day when wind speeds died down in West Texas. 

4. Why didn’t the grid’s problems get fixed? 

There is no easy fix. The Texas system allows the price of electricity to swing to match supply and demand. That means high prices — and high profits — drive the development of new power plants. At times spot power prices have been as low as $20-$50 a megawatt-hour versus more than $4,000 during periods of stress. The limitation of this pricing structure was laid bare by the 2021 winter blackouts. Since then, state lawmakers have passed market reforms that require weatherization of critical infrastructure and changed rules to put more money in the pockets of the owners of power generation.  

5. What’s the big challenge? 

There’s a real clash going on over what the grid of the future should look like in Texas and across the country, especially as severe heat raises blackout risks nationally. The challenge is to make sure nuclear and fossil fuel plants that are needed right now don’t retire too early and still allow newer, cleaner technologies to flourish. Some conservative Republicans have blamed renewable energy for destabilizing the grid and have pushed for more fossil-fuel powered generators. Lawmakers passed a controversial $10 billion program providing low-interest loans and grants to build new gas-fired plants using taxpayer money, but Texans ultimately have to vote on the subsidy. 

6. Why do improvements take so long? 

Figuring out how to keep the lights on without overburdening consumers is becoming a greater challenge amid more extreme weather fueled by climate change. As such, changing the rules is often a hotly contested process pitting utilities, generators, manufacturers, electricity retailers and other groups against one another. The process became more politicized after the storm in 2021 with Republican Gov. Greg Abbott and lawmakers ordering Ercot to make changes. Building more transmission lines and connecting to other states can help, but such projects are typically tied up for years in red tape.

7. What can be done? 

The price cap for electricity was cut from $9,000/MWh to $5,000 to help avoid the punitive costs seen in the 2021 storm, though prices are allowed to spike more easily. Ercot is also contracting for more reserves to be online to help avoid supply shortfalls and improve reliability for customers, which added $1.7 billion in consumer costs alone last year. Another rule helps some gas generators pay for their fuel costs, while a more recent reform put in price floors when reserves fall to certain levels. Many power experts say that the easiest solution is to pay people to reduce their energy consumption during times of grid stress through so-called demand response programs. Factories, Bitcoin miners and other large users are already compensated to conserve during tight grid conditions.

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Affordable Clean Energy Rule Lawsuit pits EPA and coal industry allies against health groups over Clean Power Plan repeal, greenhouse gas emissions standards, climate change, public health, and state authority before the D.C. Circuit.

Key Points

A legal fight over EPA's ACE rule and CPP repeal, weighing emissions policy, state authority, climate, and public health.

✅ Challenges repeal of Clean Power Plan and adoption of ACE.

✅ EPA backed by coal, utilities; health groups seek stricter limits.

✅ D.C. Circuit to review emissions authority and state roles.

The largest trade association representing coal interests in the country has joined other business and electric utility groups in siding with the EPA in a lawsuit challenging the Trump administration's repeal of the Clean Power Plan.

The suit -- filed by the American Lung Association and the American Public Health Association -- seeks to force the U.S. Environmental Protection Agency to drop a new rule-making process that critics claim would allow higher levels of greenhouse gas emissions, further contributing to the climate crisis and negatively impacting public health.

The new rule, which the Trump administration calls the "Affordable Clean Energy rule" (ACE), "would replace the 2015 Clean Power Plan, which EPA has proposed to repeal because it exceeded EPA's authority. The Clean Power Plan was stayed by the U.S. Supreme Court and has never gone into effect," according to an EPA statement.

EPA has also moved to rewrite wastewater limits for coal power plants, signaling a broader rollback of related environmental requirements.

America's Power -- formerly the American Coalition for Clean Coal Electricity -- the U.S. Chamber of Commerce, the National Mining Association, and the National Rural Electric Cooperative Association have filed motions seeking to join the lawsuit. The U.S. Court of Appeals for the District of Columbia Circuit has not yet responded to the motion.

Separately, energy groups warned that President Trump and Energy Secretary Rick Perry were rushing major changes to electricity pricing that could disrupt markets.

"In this rule, the EPA has accomplished what eluded the prior administration: providing a clear, legal pathway to reduce emissions while preserving states' authority over their own grids," Hal Quinn, president and chief executive officer of the mining association, said when the new rule was released last month. "ACE replaces a proposal that was so extreme that the Supreme Court issued an unprecedented stay of the proposal, having recognized the economic havoc the mere suggestion of such overreach was causing in the nation's power grid."

Around the same time, a coal industry CEO blasted a federal agency's decision on the power grid as harmful to reliability.

The trade and business groups have argued that the Clean Power Plan, set by the Obama administration, was an overreach of federal power. Finalized in 2015, the plan was President Obama's signature policy on climate change, rooted in compliance with the Paris Climate Treaty. It would have set state limits on emissions from existing power plants but gave wide latitude for meeting goals, such as allowing plant operators to switch from coal to other electric generating sources to meet targets.

Former EPA Administrator Scott Pruitt argued that the rule exceeded federal statutory limits by imposing "outside the fence" regulations on coal-fired plants instead of regulating "inside the fence" operations that can improve efficiency.

The Clean Power Plan set a goal of reducing carbon emissions from power generators by 32 percent by the year 2030. An analysis from the Rhodium Group found that had states taken full advantage of the CPP's flexibility, emissions would have been reduced by as much as 72 million metric tons per year on average. Still, even absent federal mandates, the group noted that states are taking it upon themselves to enact emission-reducing plans based on market forces.

In its motion, America's Power argues the EPA "acknowledged that the [Best System of Emission Reduction] for a source category must be 'limited to measures that can be implemented ... by the sources themselves.'" If plants couldn't take action, compliance with the new rule would require the owners or operators to buy emission rate credits that would increase investment in electricity from gas-fired or renewable sources. The increase in operating costs plus federal efforts to shift power generation to other sources of energy, thereby increasing costs, would eventually force the coal-fired plants out of business.

In related proceedings, renewable energy advocates told FERC that a DOE proposal to subsidize coal and nuclear plants was unsupported by the record, highlighting concerns about market distortions.

"While we are confident that EPA will prevail in the courts, we also want to help EPA defend the new rule against others who prefer extreme regulation," said Michelle Bloodworth, president and CEO of America's Power.

"Extreme regulation" to one group is environmental and health protections to another, though.

Howard A. Learner, executive director of the Environmental Law & Policy Center of the Midwest, defended the Clean Power Plan in an opinion piece published in June.

"The Midwest still produces more electricity from coal plants than any other region of the country, and Midwesterners bear the full range of pollution harms to public health, the Great Lakes, and overall environmental quality," Learner wrote. "The new [Affordable Clean Energy] Rule is a misguided policy, moves our nation backward in solving climate change problems, and misses opportunities for economic growth and innovation in the global shift to renewable energy. If not reversed by the courts, as it should be, the next administration will have the challenge of doing the right thing for public health, the climate and our clean energy future."

When it initially filed its lawsuit against the Trump administration's Affordable Clean Energy Rule, the American Lung Association accused the EPA of "abdicat[ing] its legal duties and obligations to protect public health." It also referred to the new rule as "dangerous."

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