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Clean Power Plan Rollback signals EPA's shift to inside-the-fence efficiency at coal plants, emphasizing heat-rate improvements over sector-wide decarbonization, renewables, natural gas switching, demand-side efficiency, and carbon capture under Clean Air Act constraints.

Key Points

A policy shift by the EPA to replace broad emissions rules with plant-level efficiency standards, limiting CO2 cuts.

✅ Inside-the-fence heat-rate improvements at coal units

✅ Potential CO2 cuts limited to about 6% per plant

✅ Alternatives: fuel switching, renewables, carbon capture

President Barack Obama’s signature plan to reduce carbon dioxide emissions from electrical generation took years to develop and touched every aspect of power production and use, from smokestacks to home insulation.

The Trump administration is moving to scrap that plan and has signaled that any alternative it might adopt would take a much less expansive approach, possibly just telling utilities to operate their plants more efficiently.

That’s a strategy environmentalists say is almost certain to fall short of what’s needed.

The Trump administration is making "a wholesale retreat from EPA’s legal, scientific and moral obligation to address the threats of climate change," said former Environmental Protection Agency head Gina McCarthy, the architect of Obama’s Clean Power Plan.

President Donald Trump promised to rip up the initiative, echoing an end to the 'war on coal' message from his campaign, which mandated that states change their overall power mix, displacing coal-fired electricity with that from wind, solar and natural gas. The EPA is about to make it official, arguing the prior administration violated the Clean Air Act by requiring those broad changes to the electricity sector, according to a draft obtained by Bloomberg.

Possible Replacements

Later, the agency will also ask the public to weigh in on possible replacements. The administration will ask whether the EPA can or should develop a replacement rule -- and, if so, what actions can be mandated at individual power plants, though some policymakers favor a clean electricity standard to drive broader decarbonization.

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Such changes -- such as adding automation or replacing worn turbine seals -- would yield at most a 6 percent gain in efficiency, along with a corresponding fall in greenhouse gas emissions, according to earlier modeling by the Environmental Protection Agency and other analysts. That compares to the 32 percent drop in emissions by 2030 under Obama’s Clean Power Plan.

"In these existing plants, there’s only so many places to look for savings," said John Larsen, a director of the Rhodium Group, a research firm. "There’s only so many opportunities within a big spinning machine like that."

EPA Administrator Scott Pruitt outlined such an "inside-the-fence-line" approach in 2014, later embodied in the Affordable Clean Energy rule that industry groups backed, when he served as Oklahoma’s attorney general. Under his blueprint, states would set emissions standards after a detailed unit-by-unit analysis, looking at what reductions are possible given "the engineering limits of each facility."

The EPA has not decided whether it will promulgate a new rule at all, though it has also proposed new pollution limits for coal and gas plants in separate actions. In a forthcoming advanced notice of proposed rulemaking, the EPA will ask "what inside-the-fence-line options are legal, feasible and appropriate," according to a document obtained by Bloomberg.

Increased efficiency at a coal plant -- known as heat-rate improvement -- translates into fewer carbon-dioxide emissions per unit of electric power generated.

Under Obama, the EPA envisioned utilities would make some straightforward efficiency improvements at coal-fired power plants as the first step to comply with the Clean Power Plan. But that was expected to coincide with bigger, broader changes -- such as using more cleaner-burning natural gas, adding more renewable power projects and simply encouraging customers to do a better job turning down their thermostats and turning off their lights.

Obama’s EPA didn’t ask utilities to wring every ounce of efficiency they could out of coal-fired power plants because they saw the other options as cheaper. A plant-specific approach "would be grossly insufficient to address the public health and environmental impacts from CO2 emissions," Obama’s EPA said.

That approach might yield modest emissions reductions and, in a perverse twist, might event have the opposite effect. If utilities make coal plants more efficient -- thereby driving down operating costs -- they also make them more competitive with natural gas and renewables, "so they might run more and pollute more," said Conrad Schneider, advocacy director for the Clean Air Task Force.  

In a competitive market, any improvement in emissions produced for each unit of energy could be overwhelmed by an increase in electrical output, and debates over changes to electricity pricing under Trump and Perry added further uncertainty.

"A very minor heat rate improvement program would very likely result in increased emissions," Schneider said. "It might be worse than nothing."

Power companies want to get as much electricity as possible from every pound of coal, so they already have an incentive to keep efficiency high, said Jeff Holmstead, a former assistant EPA administrator now at Bracewell LLP. But an EPA regulation known as “new source review” has discouraged some from making those changes, for fear of triggering other pollution-control requirements, he said.

"If EPA’s replacement rule allows companies to improve efficiency without triggering new source review, it would make a real difference in terms of reducing carbon-dioxide emissions," Holmstead said.

Modest Impact

A plant-specific approach doesn’t have to mean modest impact.

"If you’re thinking about what can be done at the power plants by themselves, you don’t stop at efficiency tune-ups," said David Doniger, director of the Natural Resources Defense Council’s climate and clean air program. "You look at things like switching to natural gas or installing carbon capture and storage."

Requirements that facilities use carbon capture technology or swap in natural gas for coal could actually come close to hitting the same goals as in Obama’s Clean Power Plan -- if not go even further, Schneider said. They just would cost more.

The benefit of the Clean Power Plan "is that it enabled states to create programs and enabled companies to find a reduction strategy that was the most efficient and made the most sense for their own content," said Kathryn Zyla, deputy director of the Georgetown Climate Center. "And that flexibility was really important for the states and companies."

Some utilities, including Houston-based Calpine Corp., PG&E Corp. and Dominion Resources Inc., backed the Obama-era approach. And they are still pushing the Trump administration to be creative now.

"The Clean Power Plan achieved a thoughtful, balanced approach that gave companies and states considerable flexibility on how best to pursue that goal," said Melissa Lavinson, vice president of federal affairs and policy for PG&E’s Pacific Gas and Electric utility. “We look forward to working with the administration to devise an alternative plan for decarbonizing the U.S. economy."

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France Negative Electricity Prices highlight surplus renewables as solar and wind output exceeds demand, driving grid flexibility, demand response, and storage signals while reshaping energy markets, lowering emissions, and improving economic efficiency and energy security.

Key Points

They occur when surplus solar and wind push wholesale power prices below zero, signaling flexible, low-carbon grids.

✅ Surplus solar and wind outpace demand, flipping price signals

✅ Incentivizes demand response, storage, and flexible loads

✅ Enhances decarbonization, energy security, and market efficiency

In a remarkable feat for renewable energy, France has recently experienced negative electricity prices due to an abundant supply of solar and wind power. This development highlights the country's progress towards sustainable energy solutions and underscores the potential of renewables to reshape global energy markets.

The Surge in Renewable Energy Supply

France's electricity grid benefited from a surplus of renewable energy generated by solar panels and wind turbines. During periods of peak production, such as sunny and windy days, the supply of electricity exceeded demand, leading to negative prices and reflecting how solar is reshaping price dynamics in Northern Europe.

Implications for Energy Markets

The occurrence of negative electricity prices reflects a shift towards a more flexible and responsive energy system. It demonstrates the capability of renewables to meet substantial portions of electricity demand reliably and economically, with evidence of falling wholesale prices in many markets, challenging traditional notions of energy supply and pricing dynamics.

Technological Advancements and Policy Support

Technological advancements in renewable energy infrastructure, coupled with supportive government policies and incentives, have played pivotal roles in France's achievement. Investments in solar farms, wind farms, and grid modernization, including the launch of France's largest battery storage platform by TagEnergy, have enhanced the efficiency and reliability of renewable energy integration into the national grid.

Economic and Environmental Benefits

The adoption of renewable energy sources not only reduces greenhouse gas emissions but also fosters economic growth and energy independence. By harnessing abundant solar and wind resources, France strengthens its energy security and reduces reliance on fossil fuels, contributing to long-term sustainability goals and reflecting a continental shift as renewable power has surpassed fossil fuels for the first time.

Challenges and Future Outlook

While France celebrates the success of negative electricity prices, challenges remain in scaling renewable energy deployment and optimizing grid management. Balancing supply and demand, integrating intermittent renewables, and investing in energy storage technologies are critical for ensuring grid stability and maximizing the benefits of renewable energy, particularly in addressing clean energy's curtailment challenge across modern grids.

Global Implications

France's experience with negative electricity prices serves as a model for other countries striving to transition to clean energy economies. It underscores the potential of renewables to drive economic prosperity, mitigate climate change impacts, and reshape global energy markets towards sustainability, as seen in Germany where solar-plus-storage is now cheaper than conventional power in several contexts.

Conclusion

France's achievement of negative electricity prices driven by renewable energy surplus marks a significant milestone in the global energy transition. By leveraging solar and wind power effectively, France demonstrates the feasibility and economic viability of renewable energy integration at scale. As countries worldwide seek to reduce carbon emissions and enhance energy resilience, France's example provides valuable insights and inspiration for advancing renewable energy agendas and accelerating towards a sustainable energy future.

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New England Solar Interconnection Costs highlight distributed generation strains, transmission charges, distribution upgrades, and DAF fees as National Grid maps hosting capacity, driving queue delays and FERC disputes in Rhode Island and Massachusetts.

Key Points

Rising upfront grid upgrade and DAF charges for distributed solar in RI and MA, including some transmission costs.

✅ Upfront grid upgrades shifted to project developers

✅ DAF and transmission charges increase per MW costs

✅ Queue delays tied to hosting capacity and cluster studies

Solar developers in Rhode Island and Massachusetts say soaring charges to interconnect with the electric grid are threatening the viability of projects. 

As more large-scale solar projects line up for connections, developers are being charged upfront for the full cost of the infrastructure upgrades required, a long-common practice that they say is now becoming untenable amid debates over a new solar customer charge in Nova Scotia. 

“It is a huge issue that reflects an under-invested grid that is not ready for the volume of distributed generation that we’re seeing and that we need, particularly solar,” said Jeremy McDiarmid, vice president for policy and government affairs at the Northeast Clean Energy Council, a nonprofit business organization. 

Connecting solar and wind systems to the grid often requires upgrades to the distribution system to prevent problems, such as voltage fluctuations and reliability risks highlighted by Australian distributors in their networks. Costs can vary considerably from place to place, depending on the amount of distributed generation coming online and the level of capacity planning by regulators, said David Feldman, a senior financial analyst at the National Renewable Energy Laboratory.

“Certainly the Northeast often has more distribution challenges than much of the rest of the country just because it’s more populous and often the infrastructure is older,” he said. “But it’s not unique to the Northeast — in the Midwest, for example, there’s a significant amount of wind projects in the queues and significant delays.”

In Rhode Island and Massachusetts, where strong incentive programs are driving solar development, the level of solar coming online is “exposing the under-investment in the distribution system that is causing these massive costs that National Grid is assigning to particular projects or particular groups of projects,” McDiarmid said. “It is going to be a limiting factor for how much clean energy we can develop and bring online.”

Frank Epps, chief executive officer at Energy Development Partners, has been developing solar projects in Rhode Island since 2010. In that time, he said, interconnection charges on his projects have grown from about $80,000-$120,000 per megawatt to more than $400,000 per megawatt. He attributed the increase to a lack of investment in the distribution network by National Grid over the last decade.

He and other developers say the utility is now adding further to their costs by passing along not just the cost of improving the distribution system — the equivalent of the city street of the grid that brings power directly to customers — but also costs for modifying the transmission system — the interstate highway that moves bulk power over long distances to substations. 

Solar developers who are only requesting to hook into the distribution system, and not applying for transmission service, say they should not be charged for those additional upgrades under state interconnection rules unless they are properly authorized under the federal law that governs the transmission system. 

A Rhode Island solar and wind developer filed a complaint with the Federal Energy Regulatory Commission in February over transmission system improvement charges for its four proposed solar projects. Green Development said National Grid subsidiaries Narragansett Electric and New England Power Company want to charge the company more than $500,000 a year in operating and maintenance expenses assessed as so-called direct assignment facility charges. 

“This amount nearly doubles the interconnection costs associated with the projects,” which total 38.4 megawatts in North Smithfield, the company says in its complaint. “Crucially, these charges are linked to recovering costs associated with providing transmission service — even though no such transmission service is being provided to Green Development.”

But Ted Kresse, a spokesperson for National Grid, said the direct assignment facility, or DAF, construct has been in place for decades and has been applied to any customer affecting the need for transmission upgrades.

“It is the result of the high penetration and continued high volume of distributed generation interconnections that has recently prompted the need for transmission upgrades, and subsequently the pass-through of the associated DAF charges,” he said. 

Several complaints before the Rhode Island Public Utilities Commission object to these DAF and other transmission charges.

One petition for dispute resolution concerns four solar projects totaling 40 MW being developed by Energy Development Partners in a former gravel pit in North Kingstown. Brown University has agreed to purchase the power. 

The developer signed interconnection service agreements with Narragansett Electric in 2019 requiring payment of $21.6 million for costs associated with connecting the projects at a new Wickford Junction substation. Last summer, Narragansett sought to replace those agreements with new ones that reclassified a portion of the costs as transmission-level costs, through New England Power, National Grid’s transmission subsidiary.

That shift would result in additional operational and maintenance charges of $835,000 per year for the estimated 35-year life of the projects, the complaint says.

“This came as a complete shock to us,” Epps said. “We’re not just paying for the maintenance of a new substation. We are paying a share of the total cost that the system owner has to own and operate the transmission system. So all of the sudden, it makes it even tougher for distributed energy resources to be viable.”

In its response to the petition, National Grid argues that the charges are justified because the solar projects will require transmission-level upgrades at the new substation. The company argues that the developer should be responsible for the costs rather than ratepayers, “who are already supporting renewable energy development through their electric rates.”

Seth Handy, one of the lawyers representing Green Development in the FERC complaint, argues that putting transmission system costs on distribution assets is unfair because the distributed resources are “actually reducing the need to move electricity long distances. We’ve been fighting these fights a long time over the underestimating of the value of distributed energy in reducing system costs.”

Handy is also representing the Episcopal Diocese of Rhode Island before the state Supreme Court in its appeal of an April 2020 public utilities commission order upholding similar charges for a proposed 2.2-megawatt solar project at the diocese’s conference center and camp in Glocester. 

Todd Bianco, principal policy associate at the utilities commission, said neither he nor the chairperson can comment on the pending dockets contesting these charges. But he noted that some of these issues are under discussion in another docket examining National Grid’s standards for connecting distributed generation. Among the proposals being considered is the appointment of an independent ombudsperson to resolve interconnection disputes. 

Separately, legislation pending before the Rhode Island General Assembly would remove responsibility for administering the interconnection of renewable energy from utilities, and put it under the authority of the Rhode Island Infrastructure Bank, a financing agency.

Handy, who recently testified in support of the bill, said he believes National Grid has too many conflicting interests to administer interconnecting charges in a timely, transparent and fair fashion, and pointed to utility moves such as changes to solar compensation in other states as examples. In particular, he noted the company’s interests in expanding natural gas infrastructure. 

“There are all kinds of economic interests that they have that conflict with our state policy to provide lower-cost renewable energy and more secure energy solutions,” Handy said.

In testimony submitted to the House Committee on Corporations opposing the legislation, National Grid said such powers are well beyond the purpose and scope of the infrastructure bank. And it cited figures showing Rhode Island is third in the country for the most installed solar per square mile (behind New Jersey and Massachusetts).

Nadav Enbar, program manager at the Electric Power Research Institute, a nonprofit research organization for the utility industry, said interconnection delays and higher costs are becoming more common due to “the incredible uptake” in distributed renewable energy, particularly solar.

That’s impacting hosting capacity, the room available to connect all resources to a circuit without causing adverse harm to reliability and safety. 

“As hosting capacity is being reduced, it’s causing an increasing number of situations where utilities need to study their systems to guarantee interconnection without compromising their systems,” he said. “And that is the reason why you’re starting to see some delays, and it has translated into some greater costs because of the need for upgrades to infrastructure.”

The cost depends on the age or absence of infrastructure, projected load growth, the number of renewable energy projects in the queue, and other factors, he said. As utilities come under increasing pressure to meet state renewable goals, and as some states pilot incentives like a distributed energy rebate in Illinois to drive utility innovation, some (including National Grid) are beginning to provide hosting capacity maps that provide detailed information to developers and policymakers about the amount of distributed energy that can be accommodated at various locations on the grid, he said. 

In addition, the coming availability of high-tech “smart inverters” should help ease some of these problems because they provide the grid with more flexibility when it comes to connecting and communicating with distributed energy resources, Enbar said. 

In Massachusetts, the Department of Public Utilities has opened a docket to explore ways to better plan for and share the cost of upgrading distribution infrastructure to accommodate solar and other renewable energy sources as part of a grid overhaul for renewables nationwide. National Grid has been conducting “cluster studies” there that attempt to analyze the transmission impacts of a group of solar projects and the corresponding interconnection cost to each developer.

Kresse, of National Grid, said the company favors cost-sharing methodologies under consideration that would “provide a pathway to spread cost over the total enabled capacity from the upgrade, as opposed to spreading the cost over only those customers in the queue today.” 

Solar developers want regulators to take an even broader approach that factors in how the deployment of renewables and the resulting infrastructure upgrades benefit not just the interconnecting generator, but all customers. 

“Right now, if your project is the one that causes a multimillion-dollar upgrade, you are assigned that cost even though that upgrade is going to benefit a lot of other projects, as well as make the grid stronger,” said McDiarmid, of the clean energy council. “What we’re asking for is a way of allocating those costs among a variety of developers, as well as to the grid itself, meaning ratepayers. There’s a societal benefit to increasing the modernization of the grid, and improving the resilience of the grid.”

In the meantime, BlueHub Capital, a Boston-based solar developer focused on serving affordable housing developments, recently learned from National Grid that, as a part of one of the area studies, it will be required to pay $5.8 million in transmission and distribution upgrades to interconnect a 2-megawatt solar-plus-storage project that leverages cheaper batteries to enhance resilience, approved for a brownfield site in Gardner, Massachusetts. 

According to testimony submitted to the department, the sum is supposed to be paid within the next year, even though the project will have to wait to be interconnected until April 2027, when a new transmission line is completed. In addition, BlueHub will be responsible for DAF charges totaling $3.4 million over the 20-year life of the project. 

“We’re being asked to pay a fortune to provide solar that the state wants,” said DeWitt Jones, BlueHub’s president. “It’s so expensive that the upgrades are driving everyone out of the interconnection queue. The costs stay the same, but they fall on fewer projects. We need a process of grid design and modernization to guide this.”

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Manitoba Hydro capacity constraints challenge clean energy growth as industrial demand, hydrogen projects, EV batteries, and electrification strain the grid; limited surplus, renewables, storage, and transmission bottlenecks hinder new high-load connections.

Key Points

Limited surplus power blocks new energy-intensive loads until added generation and transmission expand Manitoba's grid.

✅ No firm commitments for new energy-intensive industrial customers

✅ Single large load could consume remaining surplus capacity

✅ New renewables need transmission; gas, nuclear face trade-offs

Manitoba Hydro lacks the capacity to provide electricity to any new "energy intensive" industrial customers, the Crown corporation warns in a confidential briefing note that undercuts the idea this province can lure large businesses with an ample supply of clean, green energy, as the need for new power generation looms for the utility.

On July 28, provincial economic development officials unveiled an "energy roadmap" that said Manitoba Hydro must double or triple its generating capacity, as electrical demand could double over the next two decades in order to meet industrial and consumer demand for electricity produced without burning fossil fuels.

Those officials said 18 potential new customers with high energy needs were looking at setting up operations in Manitoba — and warned the province must be careful to choose businesses that provide the greatest economic benefit as well as the lowest environmental impact.

In a briefing note dated Sept. 13, obtained by CBC News, Manitoba Hydro warns it doesn't have enough excess power to hook up any of these new heavy electricity-using customers to the provincial power grid.

There are actually 57 proposals to use large volumes of electricity, Hydro says in the note, including eight projects already in the detailed study phase and nine where the proponents are working on construction agreements.

"Manitoba Hydro is unable to offer firm commitments to prospective customers that may align with Manitoba's energy roadmap and/or provincial economic development objectives," Hydro warns in the note, explaining it is legally obliged to serve all existing customers who need more electricity.

"As such, Manitoba Hydro cannot reserve electric supply for particular projects."

Hydro says in the note its "near-term surplus electricity supply" is so limited amid a Western Canada drought that "a single energy-intensive connection may consume all remaining electrical capacity."

Adding more electrical generating capacity won't be easy, even with new turbine investments underway, and will not happen in time to meet demands from customers looking to set up shop in the province, Hydro warns.

The Crown corporation goes on to say it's grappling with numerous requests from existing and prospective energy-intensive customers, mainly for producing hydrogen, manufacturing electric vehicle batteries and switching from fossil fuels to electricity, such as to use electricity for heat in buildings.

In a statement, Hydro said it wants to ensure Manitobans know the corporation is not running out of power — just the ability to meet the needs of large new customers, and continues to provide clean energy to neighboring provinces today.

"The size of loads looking to come to Manitoba are significantly larger than we typically see, and until additional supply is available, that limits our ability to connect them," Hydro spokesperson Bruce Owen said in a statement.

Adding wind power or battery storage, for example, would require the construction of more transmission lines, and deals such as SaskPower's purchase depend on that interprovincial infrastructure as well.

Natural gas plants are relatively inexpensive to build but do not align with efforts to reduce carbon emissions. Nuclear power plants require at least a decade of lead time to build, and tend to generate local opposition.

Hydro has also ruled out building another hydroelectric dam on the Nelson River, where the Conawapa project was put on hold in 2014.

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Ukraine Power Grid Restoration accelerates across liberated Kharkiv, restoring electricity, heat, and water amid missile and drone strikes, demining operations, blackouts, and winterization efforts, showcasing resilience, emergency repairs, and critical infrastructure recovery.

Key Points

Ukraine's rapid push to repair war-damaged grids, restore heat and water, and stabilize key services before winter.

✅ Priority repairs restore electricity and water in liberated Kharkiv.

✅ Crews de-mine lines and work under shelling, drones, and missiles.

✅ Winterization adds generators, mobile stoves, and large firewood supplies.

On the freshly liberated battlefields of northeast Ukraine, a pile of smashed glass windows outside one Soviet-era block of apartments attests to the violence of six months of Russian occupation, and of Ukraine’s sweeping recent military advances.

Indoors, in cramped apartments, residents lived in the dark for weeks on end.

Now, with a hard winter looming, they marvel at the speed and urgency with which Ukrainian officials have restored another key ingredient to their survival: electric power, a critical effort to keep the lights on this winter across communities.

Among those things governments strive to provide are security, opportunity, and minimal comfort. With winter approaching, and Russia targeting Ukraine’s infrastructure, add to that list heat and light, even as Russia hammers power plants nationwide. It’s requiring a concerted effort.

“Thank God it works! Electricity is civilization – it is everything,” says Antonina Krasnokutska, a retired medical worker, looking affectionately at the lightbulb that came on the day before, and now burns again in her tiny spotless kitchen.

“Without electricity there is no TV, no news, no clothes washing, no charging the phone,” says Ms. Krasnokutska, her gray hair pulled back and a small crucifix around her neck.

“Before, it was like living in the Stone Age,” says her grown son, Serhii Krasnokutskyi, who is more than a head taller. “As soon as it got dark, everyone would go to sleep.”

He shows a picture on his phone from a few days earlier, of a tangle of phone and computer charging cables – including his – plugged in at a local shop with a generator.

“We are very grateful for the people who repaired this electricity, even with shelling continuing,” he says. “They have a very complicated job.”

Indeed, although a lack of power might have been a novel inconvenience during the warm summer season, it increasingly has become a matter of great urgency for Ukrainian citizens and officials.

Coping through Ukraine’s winter with dignity and any degree of security will require courage and perseverance, as the severity and suffering that the season can bring here are being weaponized by Russia, as it seeks to compensate for a string of battlefield losses.

In recent days, Russian attacks have specifically targeted Ukraine’s electrical and other civilian infrastructure – all with the apparent aim of making this winter as hard as possible for Ukrainians, even as Moscow employs other measures to spread the hardship across Europe, while Ukraine helps Spain amid blackouts through grid support.

Ukrainian President Volodymyr Zelenskyy said Monday that Russian barrages across the country with missiles and Iran-supplied kamikaze drones had destroyed 30% of Ukraine’s power stations in the previous eight days, including strikes on western Ukraine that caused outages. Thousands of towns have been left without electricity.

Kharkiv’s challenges
Emblematic of the national challenge is the one facing officials in the northeast Kharkiv region, where Ukraine recaptured more than 3,000 square miles in a September counteroffensive. Ukrainian forces are still making gains on that front, as well as in the south toward Kherson, where Wednesday Russia started evacuating civilians from the first major city it occupied, after launching its three-pronged invasion last February.

Across the Kharkiv region, Ukrainians are stockpiling as much wood, fuel, and food as possible while they still can, and adopting new energy solutions as they prepare, from sources as diverse as the floorboards of destroyed schools and the pine forests in Izium, which are pockmarked with abandoned Russian trenches adjacent to a mass burial site.

“Of course, we have this race against time,” says Serhii Mahdysyuk, the Kharkiv regional director in charge of housing, services, fuel, and energy. “Unfortunately, we probably stand in front of the biggest challenge in Ukraine.”

That is not only because of the scale of liberated territory, he says, but also because the Kharkiv region shares a long border with Russia, as well as with the Russian-controlled areas of the eastern Donbas.

“It’s a great mixture of all threats, and we are sure that shelling and bombings will continue, but we are ready for this,” says Mr. Mahdysyuk. “We know our weak spots that Russia can destroy, but we are prepared for what to do in these situations.”

Ukraine’s battlefield gains have meant a surging need to pick up the pieces after Russian occupation, even as electricity reserves are holding if no new strikes occur, to ensure habitable conditions as more and more surviving residents require services, and as others return to scenes of devastation.

Restoring electricity is the top priority, amid shifting international assistance such as the end of U.S. grid support, because that often restarts running water, too, says Mr. Mahdysyuk. But before that, the area beneath broken power lines must be de-mined.

Indeed, members of an electricity team reconnecting cables on the outskirts of Balakliia – one of the first towns to see power restored, at the end of September – say they lost two fellow workers in the previous two weeks. One died after stepping on an anti-personnel mine, another when his vehicle hit an anti-tank device.

Ukrainian electricity workers restore power lines damaged during six months of Russian military occupation in Balakliia, Ukraine, Sept. 29, 2022. Ukrainians in liberated territory say the restoration of the electrical grid, and with it often the water supply, is a return to civilization.
“For now, our biggest problem is mines,” says the team leader, who gave the name Andrii. “It’s fine within the cities, but in the fields it’s a disaster because it’s very difficult to see them. There is a lot of [them] around here – it will take years and years to get rid of.”

Yet officials only have a few weeks to execute plans to provide for hundreds of thousands of residents in this region, in their various states of need and distress. Some 50 field kitchens capable of feeding 200 to 300 people each have been ordered. Another 1,000 mobile stoves are on their way.

And authorities will provide nearly 200,000 cubic yards of firewood for those who have no access to it, and may have no other means of keeping warm – or where shelling continues to disrupt repairs, says Mr. Mahdysyuk.

“The level of opportunity and resources we have is not the same as the level of destruction,” he says. People in districts and buildings too destroyed to have services restored soon, such as in Saltivka in Kharkiv city, may be moved.

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AWS Renewable Energy Projects deliver new wind power for AWS data centers in Ireland, Sweden, and the US, adding 229 MW and 670,000 MWh annually, supporting 100% renewable targets and global cloud sustainability.

Key Points

AWS projects add wind power in Ireland, Sweden, and the US to supply clean energy for AWS data centers.

✅ 229 MW new wind capacity; 670,000 MWh annual generation

✅ Sites: Donegal (IE), Backhammar (SE), Tehachapi (US)

✅ Advances 100% renewable goal for global AWS infrastructure

 Amazon has announced three new clean energy projects as part of its long-term goal to power all Amazon Web Services (AWS) global infrastructure with renewable energy. These projects – one in Ireland, one in Sweden, and one in the United States – will deliver wind-generated energy that will total over 229 megawatts (MW) of power, with expected generation of over 670,000 megawatt hours (MWh) of renewable energy annually. The new projects are part of AWS’s long-term commitment to achieve 100 percent renewable energy for its global infrastructure. In 2018, AWS exceeded 50 percent renewable energy for its global infrastructure.

Once complete, these projects, combined with AWS’s previous nine renewable energy projects, reflect how renewable power developers benefit from diversified sources and are expected to generate more than 2,700,000 MWh of renewable energy annually – equivalent to the annual electricity consumption of over 262,000 US homes, which is approximately the size of the city of Nashville, Tennessee.

“Each of these projects brings us closer to our long-term commitment to use 100 percent renewable energy to power our global AWS infrastructure,” said Peter DeSantis, Vice President of Global Infrastructure and Customer Support, Amazon Web Services. “These projects are well-positioned to serve AWS data centers in Ireland, Sweden, and the US. We expect more projects in 2019 as we continue toward our goal of powering all AWS global infrastructure with renewable energy.”

Amazon has committed to buying the energy from a new wind project in Ireland, a 91.2 MW wind farm in Donegal. The Donegal wind farm project is expected to deliver clean energy no later than the end of 2021.

“AWS’s investment in renewable projects in Ireland illustrates their continued commitment to adding clean energy to the grid and it will make a positive contribution to Ireland’s renewable energy goals,” said Leo Varadkar, An Taoiseach of Ireland. “As a significant employer in Ireland, it is very encouraging to see Amazon taking a lead on this issue. We look forward to continuing to work with Amazon as we strive to make Ireland a leader on renewable energy.”

Amazon will also purchase 91 MW of power from a new wind farm in Bäckhammar, Sweden, which is expected to deliver renewable energy by the end of 2020.

“Sweden has long been known for ambitious renewable energy goals, and this new wind farm showcases both our country’s leadership and AWS’s commitment to renewable energy,” said Anders Ygeman, Sweden’s Minister for Energy and Digital Development. “This is a significant step in Sweden’s renewable energy production as we work toward our target of 100 percent renewable energy by 2040.”

California leads the United States in renewable electricity generation from non-hydroelectric sources, as US solar and wind growth accelerates, and the state’s Tehachapi Mountains, where AWS’s wind farm will be located, contain some of the largest wind farms in the country. The wind farm project in Tehachapi is expected to bring up to 47 MW of new renewable energy capacity by the end of 2020.

“This announcement from AWS is great news, not just for California, but for the entire country, as it reaffirms our role as a leader in renewable energy and allows us to take an important step forward on deploying the clean energy we need to respond to climate change,” said California State Senator Jerry Hill, San Mateo and Santa Clara Counties, a member of the Senate Standing Committee on Energy, Utilities and Communications.

Beyond the sustainability initiatives focused on powering the AWS global infrastructure, Amazon recently announced Shipment Zero, which is Amazon’s vision to make all Amazon shipments net zero carbon, with 50 percent of all shipments net zero by 2030. Additional sustainability programs across the company include Amazon Wind Farm Texas, which adds more than 1 million MWh of clean energy each year, alongside Amazon Wind Farm US East that is now fully operational, demonstrating scale. In total, Amazon has enabled 53 wind and solar projects worldwide, which produce more than 1,016 MW and are expected to deliver over 3,075,636 million MWh of energy annually, while peers like Arvato's solar power plant underscore broader momentum across the industry. These projects support hundreds of jobs, while providing tens of millions of dollars of investment in local communities, with Iowa wind power offering a strong example. Amazon has also set a goal to host solar energy systems at 50 fulfillment centers by 2020. This deployment of rooftop solar systems, aided by cheap batteries that enhance storage, is part of a long-term initiative that will start in North America and spread across the globe. Amazon also implemented the District Energy Project that uses recycled energy for heating Amazon offices in Seattle. For more information on Amazon’s sustainability initiatives, visit www.amazon.com/sustainability.

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