TVAÂ’s CEO says trust the agency

By The Tennessean


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TVA will install new air pollution control equipment to three coal-burning power plants in East Tennessee, as it has previously pledged, TVAÂ’s president and CEO told a federal court recently.

A climate of tightening regulations, and the fact that TVA has already begun the upgrades, dictates finishing the upgrades, chief executive officer Tom Kilgore said.

“We’ve invested about a billion dollars… in East Tennessee,” Kilgore said. “It would be foolhardy not to complete those.”

TVA rested its case after KilgoreÂ’s testimony in federal court, where the state of North Carolina is suing to force the public electricity producer to reduce emissions by 2013. ThatÂ’s the deadline required of utilities within its borders.

Under cross-examination, Kilgore conceded that in the past TVA had made significant financial investments on plans it later abandoned, specifically the construction of a series of nuclear plants. The agency spent years building several that were later cancelled, leaving the agency deep in debt. Its debt is about $25 billion today.

TVA more recently announced it would put “scrubbers” on its Colbert coal-fired plant in Alabama to lessen emissions there, and later switched its plans. Kilgore said the agency intends to put them on its John Sevier plant in East Tennessee instead.

TVA, the nationÂ’s largest public power producer, provides electricity to distributors throughout Tennessee and parts of six other states. Most comes from burning coal, with the second-largest amount from nuclear power.

North Carolina contends that air emissions from TVAÂ’s coal-burning plants are moving over the southern Appalachian Mountains and causing problems in that state that include cardio-vascular and respiratory illnesses and deaths.

Marc Bernstein, with the North Carolina attorney generalÂ’s office, questioned whether TVA would really take action without a law hanging over it. He also discussed the years 1983-93, when money was not spent on air pollution control equipment.

Since the U.S. Environmental Protection AgencyÂ’s Clean Air Interstate Rule was shot down in federal court this month, the agency has little reason to follow through with its current plans for reductions, the stateÂ’s suit argues.

“It does not change what we’re going to do to clean up the air,” Kilgore insisted in court.

Earlier in the day, a top Tennessee air pollution chief chastised North Carolina for emissions at power plants within its own borders and defended TVA as a model operator of plants in Tennessee.

Quincy Styke, deputy director for Tennessee Division of Air Pollution Control, said TVAÂ’s operations are all properly permitted and he has no doubt that the agency will complete its plans.

He reacted with vigor when asked about North CarolinaÂ’s enactment of its Clean Smokestacks Act of 2002, which is requiring utilities in that state by 2013 to cap emissions of haze-, acid- and particle-producing sulfur dioxide and ozone-forming nitrogen oxide.

That stateÂ’s sulfur dioxide emissions rose to a high in 2005, Styke said.

“Tennessee has not enacted similar legislation because it’s not necessary,” he said.

“We follow all the federal rule.… We don’t need a statute. Tennessee has been about the business of controlling its emissions.”

North Carolina officials have said that emissions have been dropping significantly as private investor-owned utilities in the state phase in equipment as the deadline approaches.

Most of TVAÂ’s plants and employees are in Tennessee, though there are two plants in Alabama and two plants in Kentucky.

Witnesses on both TVAÂ’s and North CarolinaÂ’s side have testified that reductions of the agencyÂ’s emissions would benefit Tennesseans more, because more of its pollution affects Tennessee.

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Report: Duke Energy to release climate report under investor pressure

Duke Energy zero-coal 2050 plan outlines a decarbonized energy mix, aligning with Paris goals, cutting greenhouse gas emissions, driven by investor pressure, shifting to natural gas, extending nuclear power, and phasing out coal.

 

Key Points

An investor-driven scenario to end coal by 2050, shift to natural gas, extend nuclear plants, and manage climate risk.

✅ Eliminates coal from the generation mix by 2050

✅ Prioritizes natural gas transitions without CCS breakthroughs

✅ Extends nuclear plant licenses to limit carbon emissions

 

One of America’s largest utility companies, Duke Energy, is set to release a report later this month that sketches a drastically changed electricity mix in a carbon-constrained future.

The big picture: Duke is the latest energy company to commit to releasing a report about climate change in response to investor pressure, echoing shifts such as Europe's oil majors going electric across the sector, conveyed by non-binding but symbolically important shareholder resolutions. Duke provides electricity to more than seven million customers in the Carolinas, the Midwest and Florida.

Gritty details: The report is expected to find that coal, currently 33% of Duke’s mix, gone entirely from its portfolio by 2050 in a future scenario where the world has taken steps to cut greenhouse gas emissions, and where global coal-fired electricity use is falling markedly, to a level consistent with keeping global temperatures from rising two degrees Celsius. That’s the big ambition of the 2015 Paris climate deal, but the current commitments aren’t close to reaching that.

What they're saying: “What’s difficult about this is we are trying to overlay what we understand currently about technology,” Lynn Good, Duke CEO, told Axios in an interview on the sidelines of a major energy conference here.

She went on to say that this scenario of zero coal by 2050 doesn’t assume any breakthroughs in technology that captures carbon emissions from coal-fired power plants. “We don’t see that technology today, and we need to make economic decisions to get those units moving and replacing them with natural gas.”

Good also stressed the benefits of its several nuclear power plants, highlighting the role of sustaining U.S. nuclear power in decarbonization, which emit no carbon emissions. She said Duke isn’t considering investing in new nuclear plants, but plans to seek federal relicensing of current plants.

“If I turn them off, the resource that would replace them today is natural gas, so carbon will go up,” Good said. “Our objective is to continue to keep those plants as long as possible.”

What’s next: A spokesman said the other details of their 2050 scenario estimates will be available when the report is officially released by month’s end.

Axios reports that Duke Energy will release a report later this month that detail the utility's efforts to mitigate climate change risks and plan carbon-free electricity investments across its operations. The report includes a scenario that eliminates coal entirely from the company's power mix by 2050. Coal currently makes up about a third of Duke's generation.

Duke CEO Lynn Good told the news outlet the scenario ending coal-fired generation assumes no technological advances in emissions capture, seemingly leaving open the possibility.

Last year, a report by the Union of Concerned Scientists concluded one in four of the remaining operating coal-fired plants in the U.S. are slated for closure or conversion to natural gas, amid falling power-sector carbon emissions across the country. Duke's report is expected to be released by the end of the month.

Duke's report on its carbon plans comes at the behest of shareholders, a trend utility companies have seen growing among investors who are increasingly concerned about companies' sustainability and their financial exposure to climate policy.

Last year, a majority of shareholders of Pennsylvania utility PPL Corp. called on company management to publish a report on how climate change policies and technological innovations will affect the company's bottom line. Almost 60% of shareholders voted in favor of the non-binding proposal.

The vote, reportedly a first for the power sector, followed a similar decision by shareholders of Occidental Petroleum, which was supported by about 66% of shareholders.

Duke's Good told Axios that right now the utility does not see the coal technology on the horizon that would keep it operating plants. “We don't see that technology today, and we need to make economic decisions to get those units moving and replacing them with natural gas," Good said. However, it does not mean the utility is making near-term efforts to erase coal from its power mix. However, some utilities are taking those steps as they prepare for en energy landscape with more carbon regulations.

In addition to the 25% of coal plants heading for closure or conversion, the UCS report also said that another 17% of the nation’s operating coal plants are uneconomic compared with natural gas-fired generation, and could face retirement soon. But there is plenty of ongoing research into "clean coal" possibilities, and the federal government has expressed an interest in smaller, modular coal units.

 

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Electricity Grids Can Handle Electric Vehicles Easily - They Just Need Proper Management

EV Grid Capacity Management shows how smart charging, load balancing, and off-peak pricing align with utility demand response, DC fast charging networks, and renewable integration to keep national electricity infrastructure reliable as EV adoption scales

 

Key Points

EV Grid Capacity Management schedules charging and balances load to keep EV demand within utility capacity.

✅ Off-peak pricing and time-of-use tariffs shift charging demand.

✅ Smart chargers enable demand response and local load balancing.

✅ Gradual EV adoption allows utilities to plan upgrades efficiently.

 

One of the most frequent concerns you will see from electric vehicle haters is that the electricity grid can’t possibly cope with all cars becoming EVs, or that EVs will crash the grid entirely. However, they haven’t done the math properly. The grids in most developed nations will be just fine, so long as the demand is properly management. Here’s how.

The biggest mistake the social media keyboard warriors make is the very strange assumption that all cars could be charging at once. In the UK, there are currently 32,697,408 cars according to the UK Department of Transport. The UK national grid had a capacity of 75.8GW in 2020. If all the cars in the UK were EVs and charging at the same time at 7kW (the typical home charger rate), they would need 229GW – three times the UK grid capacity. If they were all charging at 50kW (a common public DC charger rate), they would need 1.6TW – 21.5 times the UK grid capacity. That sounds unworkable, and this is usually the kind of thinking behind those who claim the UK grid can't cope with EVs.

What they don’t seem to realize is that the chances of every single car charging all at once are infinitesimally low. Their arguments seem to assume that nobody ever drives their car, and just charges it all the time. If you look at averages, the absurdity of this position becomes particularly clear. The distance each UK car travels per year has been slowly dropping, and was 7,400 miles on average in 2019, again according to the UK Department of Transport. An EV will do somewhere between 2.5 and 4.5 miles per kWh on average, so let’s go in the middle and say 3.5 miles. In other words, each car will consume an average of 2,114kWh per year. Multiply that by the number of cars, and you get 69.1TWh. But the UK national grid produced 323TWh of power in 2019, so that is only 21.4% of the energy it produced for the year. Before you argue that’s still a problem, the UK grid produced 402TWh in 2005, which is more than the 2019 figure plus charging all the EVs in the UK put together. The capacity is there, and energy storage can help manage EV-driven peaks as well.

Let’s do the same calculation for the USA, where an EV boom is about to begin and planning matters. In 2020, there were 286.9 million cars registered in America. In 2020, while the US grid had 1,117.5TW of utility electricity capacity and 27.7GW of solar, according to the US Energy Information Administration. If all the cars were EVs charging at 7kW, they would need 2,008.3TW – nearly twice the grid capacity. If they charged at 50kW, they would need 14,345TW – 12.8 times the capacity.

However, in 2020, the US grid generated 4,007TWh of electricity. Americans drive further on average than Brits – 13,500 miles per year, according to the US Department of Transport’s Federal Highway Administration. That means an American car, if it were an EV, would need 3,857kWh per year, assuming the average efficiency figures above. If all US cars were EVs, they would need a total of 1,106.6TWh, which is 27.6% of what the American grid produced in 2020. US electricity consumption hasn’t shrunk in the same way since 2005 as it has in the UK, but it is clearly not unfeasible for all American cars to be EVs. The US grid could cope too, even as state power grids face challenges during the transition.

After all, the transition to electric isn’t going to happen overnight. The sales of EVs are growing fast, with for example more plug-ins sold in the UK in 2021 so far than the whole of the previous decade (2010-19) put together. Battery-electric vehicles are closing in on 10% of the market in the UK, and they were already 77.5% of new cars sold in Norway in September 2021. But that is new cars, leaving the vast majority of cars on the road fossil fuel powered. A gradual introduction is essential, too, because an overnight switchover would require a massive ramp up in charge point installation, particularly devices for people who don’t have the luxury of home charging. This will require considerable investment, but could be served by lots of chargers on street lamps, which allegedly only cost £1,000 ($1,300) each to install, usually with no need for extra wiring.

This would be a perfectly viable way to provide charging for most people. For example, as I write this article, my own EV is attached to a lamppost down the street from my house. It is receiving 5.5kW costing 24p (32 cents) per kWh through SimpleSocket, a service run by Ubitricity (now owned by Shell) and installed by my local London council, Barnet. I plugged in at 11am and by 7.30pm, my car (which was on about 28% when I started) will have around 275 miles of range – enough for a couple more weeks. It will have cost me around £12 ($16) – way less than a tank of fossil fuel. It was a super-easy process involving the scanning of a QR code and entering of a credit card, very similar to many parking systems nowadays. If most lampposts had one of these charging plugs, not having off-street parking would be no problem at all for owning an EV.

With most EVs having a range of at least 200 miles these days, and the average mileage per day being 20 miles in the UK (the 7,400-mile annual figure divided by 365 days) or 37 miles in the USA, EVs won’t need charging more than once a week or even every week or two. On average, therefore, the grids in most developed nations will be fine. The important consideration is to balance the load, because if too many EVs are charging at once, there could be a problem, and some regions like California are looking to EVs for grid stability as part of the solution. This will be a matter of incentivizing charging during off-peak times such as at night, or making peak charging more expensive. It might also be necessary to have the option to reduce charging power rates locally, while providing the ability to prioritize where necessary – such as emergency services workers. But the problem is one of logistics, not impossibility.

There will be grids around the world that are not in such a good place for an EV revolution, at least not yet, and some critics argue that policies like Canada's 2035 EV mandate are unrealistic. But to argue that widespread EV adoption will be an insurmountable catastrophe for electricity supply in developed nations is just plain wrong. So long as the supply is managed correctly to make use of spare capacity when it’s available as much as possible, the grids will cope just fine.

 

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Ontario's Clean Electricity Regulations: Paving the Way for a Greener Future

Ontario Clean Electricity Regulations accelerate renewable energy adoption, drive emissions reduction, and modernize the smart grid with energy storage, efficiency targets, and reliability upgrades to support decarbonization and a stable power system for Ontario.

 

Key Points

Standards to cut emissions, grow renewables, improve efficiency, and modernize the grid with storage and smart systems.

✅ Phases down fossil generation and invests in storage.

✅ Sets utility efficiency targets to curb demand growth.

✅ Upgrades to smart grid for reliability and resiliency.

 

Ontario has taken a significant step forward in its energy transition with the introduction of new clean electricity regulations. These regulations, complementing federal Clean Electricity Regulations, aim to reduce carbon emissions, promote sustainable energy sources, and ensure a cleaner, more reliable electricity grid for future generations. This article explores the motivations behind these regulations, the strategies being implemented, and the expected impacts on Ontario’s energy landscape.

The Need for Clean Electricity

Ontario, like many regions around the world, is grappling with the effects of climate change, including more frequent and severe weather events. In response, the province has set ambitious targets to reduce greenhouse gas emissions and increase the use of renewable energy sources, reflecting trends seen in Alberta’s path to clean electricity across Canada. The electricity sector plays a central role in this transition, as it is responsible for a significant portion of the province’s carbon footprint.

For years, Ontario has been moving away from coal as a source of electricity generation, and now, with the introduction of these new regulations, the province is taking a step further in decarbonizing its grid, including its largest competitive energy procurement to date. By setting clear goals and standards for clean electricity, the province hopes to meet its environmental targets while ensuring a stable and affordable energy supply for all Ontarians.

Key Aspects of the New Regulations

The regulations focus on encouraging the use of renewable energy sources such as wind, solar, hydroelectric, and geothermal power. One of the key elements of the plan is the gradual phase-out of fossil fuel-based energy sources. This shift is expected to be accompanied by greater investments in energy storage solutions, including grid batteries, to address the intermittency issues often associated with renewable energy sources.

Ontario’s new regulations also emphasize the importance of energy efficiency in reducing overall demand. As part of this initiative, utilities and energy providers will be required to meet strict energy-saving targets and participate in new electricity auctions designed to reduce costs, ensuring that both consumers and businesses are incentivized to use energy more efficiently.

In addition, the regulations promote technological innovation in the electricity sector. By supporting the development of smart grids, energy storage technologies, and advanced power management systems, Ontario is positioning itself to become a leader in the global energy transition.

Impact on the Economy and Jobs

One of the anticipated benefits of the clean electricity regulations is their positive impact on Ontario’s economy. As the province invests in renewable energy infrastructure and clean technologies, new job opportunities are expected to arise in industries such as manufacturing, construction, and research and development. These regulations also encourage innovation in energy services, which could lead to the growth of new companies and industries, while easing pressures on industrial ratepayers through complementary measures.

Furthermore, the transition to cleaner energy is expected to reduce the long-term costs associated with climate change. By investing in sustainable energy solutions now, Ontario will help mitigate the financial burdens of environmental damage and extreme weather events in the future.

Challenges and Concerns

While the new regulations have been widely praised for their environmental benefits, they are not without their challenges. One of the primary concerns is the potential cost to consumers, and some Ontario hydro policy critique has called for revisiting legacy pricing approaches to improve affordability. While renewable energy sources have become more affordable over the years, transitioning from fossil fuels could still result in higher electricity prices in the short term. Additionally, the implementation of new technologies, such as smart grids and energy storage, will require substantial upfront investment.

Moreover, the intermittency of renewable energy generation poses a challenge to grid stability. Ontario’s electricity grid must be able to adapt to fluctuations in energy supply as more variable renewable sources come online. This challenge will require significant upgrades to the grid infrastructure and the integration of storage solutions to ensure reliable energy delivery.

The Road Ahead

Ontario’s clean electricity regulations represent an important step in the province’s commitment to combating climate change and transitioning to a sustainable, low-carbon economy. While there are challenges to overcome, the benefits of cleaner air, reduced emissions, and a more resilient energy system will be felt for generations to come. As the province continues to innovate and lead in the energy sector, Ontario is positioning itself to thrive in the green economy of the future.

 

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Potent greenhouse gas declines in the US, confirming success of control efforts

US SF6 Emissions Decline as NOAA analysis and EPA mitigation show progress, with atmospheric measurements and Greenhouse Gas Reporting verifying reductions from the electric power grid; sulfur hexafluoride's extreme global warming potential underscores inventory improvements.

 

Key Points

A documented drop in US sulfur hexafluoride emissions, confirmed by NOAA atmospheric data and EPA reporting reforms.

✅ NOAA towers and aircraft show 2007-2018 decline

✅ EPA reporting and utility mitigation narrowed inventory gaps

✅ Winter leaks and servicing signal further reduction options

 

A new NOAA analysis shows U.S. emissions of the super-potent greenhouse gas sulfur hexafluoride (SF6) have declined between 2007-2018, likely due to successful mitigation efforts by the Environmental Protection Agency (EPA) and the electric power industry, with attention to SF6 in the power industry across global markets. 

At the same time, significant disparities that existed previously between NOAA’s estimates, which are based on atmospheric measurements, and EPA’s estimates, which are based on a combination of reported emissions and industrial activity, have narrowed following the establishment of the EPA's Greenhouse Gas Reporting Program. The findings, published in the journal Atmospheric Chemistry and Physics, also suggest how additional emissions reductions might be achieved. 

SF6 is most commonly used as an electrical insulator in high-voltage equipment that transmits and distributes electricity, and its emissions have been increasing worldwide as electric power systems expand, even as regions hit milestones like California clean energy surpluses in recent years. Smaller amounts of SF6 are used in semiconductor manufacturing and in magnesium production. 

SF6 traps 25,000 times more heat than carbon dioxide over a 100-year time scale for equal amounts of emissions, and while CO2 emissions flatlined in 2019 globally, that comparison underscores the potency of SF6. That means a relatively small amount of the gas can have a significant impact on climate warming. Because of its extremely large global warming potential and long atmospheric lifetime, SF6 emissions will influence Earth’s climate for thousands of years.

In this study, researchers from NOAA’s Global Monitoring Laboratory, as record greenhouse gas concentrations drive demand for better data, working with colleagues at EPA, CIRES, and the University of Maryland, estimated U.S. SF6 emissions for the first time from atmospheric measurements collected at a network of tall towers and aircraft in NOAA’s Global Greenhouse Gas Reference Network. The researchers provided an estimate of SF6 emissions independent from the EPA’s estimate, which is based on reported SF6 emissions for some industrial facilities and on estimated SF6 emissions for others.

“We observed differences between our atmospheric estimates and the EPA’s activity-based estimates,” said study lead author Lei Hu, a Global Monitoring Laboratory researcher who was a CIRES scientist at the time of the study. “But by closely collaborating with the EPA, we were able to identify processes potentially responsible for a significant portion of this difference, highlighting ways to improve emission inventories and suggesting additional emission mitigation opportunities, such as forthcoming EPA carbon capture rules for power plants, in the future.” 

In the 1990s, the EPA launched voluntary partnerships with the electric power, where power-sector carbon emissions are falling as generation shifts, magnesium, and semiconductor industries to reduce SF6 emissions after the United States recognized that its emissions were significant. In 2011, large SF6 -emitting facilities were required to begin tracking and reporting their emissions under the EPA Greenhouse Gas Reporting Program. 

Hu and her colleagues documented a decline of about 60 percent in U.S. SF6 emissions between 2007-2018, amid global declines in coal-fired power in some years—equivalent to a reduction of between 6 and 20 million metric tons of CO2 emissions during that time period—likely due in part to the voluntary emission reduction partnerships and the EPA reporting requirement. A more modest declining trend has also been reported in the EPA’s national inventories submitted annually under the United Nations Framework Convention on Climate Change. 

Examining the differences between the NOAA and EPA independent estimates, the researchers found that the EPA’s past inventory analyses likely underestimated SF6 emissions from electrical power transmission and distribution facilities, and from a single SF6 production plant in Illinois. According to Hu, the research collaboration has likely improved the accuracy of the EPA inventories. The 2023 draft of the EPA’s U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 used the results of this study to support revisions to its estimates of SF6 emissions from electrical transmission and distribution. 

The collaboration may also lead to improvements in the atmosphere-based estimates, helping NOAA identify how to expand or rework its network to better capture emitting industries or areas with significant emissions, according to Steve Montzka, senior scientist at GML and one of the paper’s authors.

Hu and her colleagues also found a seasonal variation in SF6 emissions from the atmosphere-based analysis, with higher emissions in winter than in summer. Industry representatives identified increased servicing of electrical power equipment in the southern states and leakage from aging brittle sealing materials in the equipment in northern states during winter as likely explanations for the enhanced wintertime emissions—findings that suggest opportunities for further emissions reductions.

“This is a great example of the future of greenhouse gas emission tracking, where inventory compilers and atmospheric scientists work together to better understand emissions and shed light on ways to further reduce them,” said Montzka.

 

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It's CHEAP but not necessarily easy: Crosbie introduces PCs' Newfoundland electricity rate reduction strategy

Crosbie Hydro Energy Action Plan outlines rate mitigation for Muskrat Falls, leveraging Nalcor oil revenues, export sales, Holyrood savings, and potential Hydro-Quebec taxation to keep Newfoundland and Labrador electricity rates near 14.67 cents/kWh.

 

Key Points

PC plan to cap post-Muskrat rates by using Nalcor revenues, exports, and savings, with optional Accord funds.

✅ $575.4M yearly to hold rates near 14.67 cents/kWh

✅ Sources: Nalcor oil $231M, Holyrood $150M, rates/dividends $123.4M

✅ Options: export sales, restructuring, Atlantic Accord, HQ tax

 

Newfoundland and Labrador PC Leader Ches Crosbie says Muskrat Falls won't drive up electricity rates, a goal consistent with an agreement to shield ratepayers from cost overruns, if he's elected premier.

According to Crosbie, who presented the party's Crosbie Hydro Energy Action Plan — acronym CHEAP — at a press conference Monday, $575.4 million is needed per year in order to keep rates from ballooning past 14.67 cents per kilowatt hour.

Here's where he thinks the money could come from:

  • Hydro rates and dividends — $123.4 million
  • Export sales — $40.1 million
  • Nalcor restructuring — $30 million
  • Holyrood savings — $150  million
  • Nalcor oil revenue — $231 million

The oil money, Crosbie said, isn't going into government coffers but being invested into the offshore which, he said, is a good place for it.

"But the plan from the beginning around Muskrat Falls was that if there was need for it — for mitigation for rates — that those revenues and operating cash flows from Nalcor oil and gas would be available to be recycled into rate mitigation, as reflected in a recent financial update on the pandemic's impact. and that's what we're going to have to do," he said.

According to Crosbie, his numbers come from the preliminary stage of the Public Utilities Board process, even as rate mitigation talks have lacked public details.

This is a recent aerial view of the Muskrat Falls project in central Labrador. The project is more than 90 per cent complete, with first power forecast for late 2019, alongside Ottawa's $5.2B support for the project. (Nalcor)

"I'm telling you this is the best information available to anyone outside of government," he said. "We're working on what we can."

The PUB estimated Nalcor restructuring could save between $10 million and $15 million, according to Crosbie, but he figures there's "enough duplication and overpayment involved in the way things are now set up that we can find $30 million there."

Currently, provincial ratepayers pay about 12 cents per kilowatt hour as electricity users have started paying for Muskrat Falls costs.

Crosbie's $575.4-million figure would put rates at 14.67 cents per kilowatt-hour in 2021, where his plan pledges to keep them.

A recent Public Utilities Board Report says there's a potential $10 million to $15 million in savings from Nalcor, but Crosbie says he can find $30 million. (CBC)

"The promise is that Muskrat Falls, when it comes online — comes in service — will not increase your rates. Between now and when that happens there are rate increases already in the pipeline up to that level of [14.67 cents per kilowatt-hour] … so that is the baseline target rate at which rates will be kept.

"In other words, Muskrat will not drive up prices for electricity to consumers beyond that point."

In addition to those savings, Crosbie's plan outlined two further steps.

"We think it could be done out of the resources that I've just identified now, but if there's a problem with that, and as a temporary measure, we can use a modest amount of the Atlantic Accord review, fiscal review, revenues," he said.

 

Plan 'nothing new'

Premier Dwight Ball slammed the plan at the House of Assembly on Monday, saying it lacked insight.

"It was a copy and paste exercise," he told reporters. "There's nothing new in that plan. Not at all."

"We're not leaving any stone unturned of where the opportunity would be to actually generate revenue," he said.  "We are genuinely concerned about rate mitigation and we've got to get a plan in place."

 

Potential to tax Hydro-Québec

Crosbie also said there's potential to tax Hydro-Québec.

According to Crosbie, tax exemptions that expired in 2016 allow the province to tax exports from the Upper Churchill, which, he said, could result in "hundreds of millions or billions" in revenue.

"It's not my philosophy to immediately go and do that because that would generate litigation — who needs more of that? — but we do need to let Quebec know that we're very aware of that, and aware of that opportunity, and invite them to come talk about a whole host of issues," Crosbie said.

Crosbie said the tax would also have to be applied to domestic consumption.

"But so massive is the potential revenue from the Upper Churchill export that there would be ways to mitigate that and negate the effect of that on consumers in the province."

Crosbie said with the Atlantic Accord revenue, he could still present a balanced budget by 2022.

 

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WEC Energy Group to buy 80% stake in Illinois wind farm for $345 million

WEC Energy Blooming Grove Investment underscores Midwest renewable energy growth, with Invenergy, GE turbines, and 250 MW wind power capacity, tax credits, PPAs, and utility-scale generation supplying corporate offtakers via long-term contracts.

 

Key Points

It is WEC Energy's $345M purchase of an 80% stake in Invenergy's 250 MW Blooming Grove wind farm in Illinois.

✅ 94 GE turbines; 250 MW utility-scale wind capacity

✅ Output contracted to two multinational offtakers

✅ Eligible for 100% bonus depreciation and wind tax credits

 

WEC Energy Group, the parent company of We Energies, is buying an 80% stake in a wind farm, as seen with projects like Enel's 450 MW wind farm coming online, in McLean County, Illinois, for $345 million.

The wind farm, known as the Blooming Grove Wind Farm, is being developed by Invenergy, which recently completed the largest North American wind build with GE partners, a company based in Chicago that develops wind, solar and other power projects. WEC Energy has invested in several wind farms developed by Invenergy.

With the agreement announced Monday, WEC Energy will have invested more than $1.2 billion in wind farms in the Midwest, echoing heartland investment growth across the region. The power from the wind farms is sold to other utilities or companies, as federal initiatives like DOE wind awards continue to support innovation, and the projects are separate from the investments made by WEC Energy's regulated utilities, such as We Energies, in wind power.

The project, which will consist of 94 wind turbines from General Electric, is expected to be completed this year, similar to recent project operations in the sector, and will have a capacity of 250 megawatts, WEC said in a news release.

Affiliates of two undisclosed multinational companies akin to EDF's offshore investment activity have contracted to take all of the wind farm's output.

The investment is expected to be eligible for 100% bonus depreciation and, as wind economics help illustrate key trends, the tax credits available for wind projects, WEC Energy said.

 

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