New partnership to advise government on nuclear industry

Iran Power Outage Protests surge as electricity blackouts, drought, and a looming heat wave spark unrest in Tehran, Shiraz, and more, with chants against leadership, strikes, and sanctions-driven economic pressures mounting.

Key Points

Protests across Iran over blackouts, drought, and economic strain challenge authorities and demand accountability.

✅ Rolling blackouts blamed on drought, heat wave, and surging demand.

✅ Chants target leadership amid strikes and wage, water shortages.

✅ Legitimacy questioned after low-turnout election and sanctions.

There have been protests in a number of cities in Iran amid rising public anger over widespread electricity blackouts.

Videos on social media appeared to show crowds in Shar-e Rey near Tehran, Shiraz, Amol and elsewhere overnight.

Some people can be heard shouting "Death to the dictator" and "Death to Khamenei" - a reference to Supreme Leader Ayatollah Ali Khamenei.

The government has apologised for the blackouts, which it has blamed on a severe drought and high demand.

Elsewhere, similar outages have had political repercussions, as a widespread power outage in Taiwan prompted a minister's resignation earlier this year.

President Hassan Rouhani explained in televised remarks on Tuesday morning that the drought meant most of the country's hydroelectric power plants were not operating, placing more pressure on thermal power plants, and that electricity consumption had surged as people used air conditioning to cope with the intense summer heat.

"I apologise to our dear people who have faced problems and suffering in the past few days and I urge them to co-operate [by cutting their electricity use]. People complain about power outages and they are right," Mr Rouhani said.

A video that has gone viral in recent days shows a woman complaining about the blackouts and corruption at a government office in the northern city of Gorgan and demanding that her comments be conveyed to "higher-ups like Mr Rouhani". "The only thing you have done is forcing hijab on us," she shouts.

The president has promised that the government will seek to resolve the problems within the next two or three weeks.

However, a power sector spokesman warned on Monday that consumption was exceeding the production capacity of Iran's power plants by 11GW, and said a "looming heat wave" could make the situation worse, as seen in Iraq's summer electricity crunch this year.

Iranians have also been complaining about water shortages and the non-payment of wages by some local authorities, while thousands of people working in Iran's oil industry have been on strike over pay and conditions, as officials discuss further energy cooperation with Iraq to ease supply pressures.

There was already widespread discontent at government corruption and the economic hardship caused by sanctions that were reinstated when the US abandoned a nuclear deal with Iran three years ago, even as Iran supplies about 40% of Iraq's electricity through cross-border sales.

Analysts say that after the historically low turnout in last month's presidential election, when more than half of the eligible voters stayed at home, the government is facing a serious challenge to its legitimacy.

Mr Rouhani will be succeeded next month by Ebrahim Raisi, a hard-line cleric close to Ayatollah Khamenei who won 62% of the vote after several prominent contenders were disqualified, while Iran finalizes power grid deals with Iraq to bolster regional ties.

The 60-year-old former judiciary chief has presented himself as the best person to combat corruption and solve Iran's economic problems, including ambitions to transmit electricity to Europe as a regional power hub.

But many Iranians and human rights activists have pointed to his human rights record, accusing him of playing a role in the executions of thousands of political prisoners in the 1980s and in the deadly crackdowns on mass anti-government protests in 2009 and 2019.

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SDG&E Ramona Microgrid delivers renewable energy and battery storage for wildfire mitigation, grid resilience, and PSPS support, powering the Cal Fire Air Attack Base with a 500 kW, 2,000 kWh lithium-ion system during outages.

Key Points

A renewable, battery-backed microgrid powering Ramona's Air Attack Base, boosting wildfire response and PSPS resilience.

✅ 500 kW, 2,000 kWh lithium-ion storage replaces diesel

✅ Keeps Cal Fire and USFS aircraft operations powered

✅ Supports PSPS continuity and rural water reliability

It figures to be another dry year — with the potential to spark wildfires in the region. But San Diego Gas & Electric just completed a renewable energy upgrade to a microgrid in Ramona that will help firefighters and reduce the effects of power shutoffs to backcountry residents.

The microgrid will provide backup power to the Ramona Air Attack Base, helping keep the lights on during outages, home to Cal Fire and the U.S. Forest Service's fleet of aircrafts that can quickly douse fires before they get out of hand.

"It gives us peace of mind to have backup power for a critical facility like the Ramona Air Attack Base, especially given the fact that fire season in California has become year-round," Cal Fire/San Diego County Fire Chief Tony Mecham said in a statement.

The air attack base serves as a hub for fixed-wing aircraft assigned to put out fires. Cal Fire staffs the base throughout the year with one two airtankers and one tactical aircraft. The base also houses the Forest Service's Bell 205 A++ helicopter and crew to protect the Cleveland National Forest. Aircraft for both CalFire and the Forest Service can also be mobilized to help fight fires throughout the state.

This summer, the Ramona microgrid won't have to rely on diesel generation. Instead, the facility next to the town's airport will be powered by a 500 kilowatt and 2,000 kilowatt-hour lithium-ion battery storage system that won't generate any greenhouse gas emissions.

"What's great about it, besides that it's a renewable resource, is that it's a permanent installation," said Jonathan Woldemariam, SDG&E's director of wildfire mitigation and vegetation management. "In other words, we don't have to roll a portable generator out there. It's something that can be leveraged right there because it's already installed and ready to go."

Microgrids have taken on a larger profile across the state because they can operate independently of the larger electric grid, where repairing California's grid is an ongoing challenge, thus allowing small areas or communities to keep the power flowing for hours at a time during emergencies.

That can be crucial in wildfire-prone areas affected by Public Safety Power Shutoffs, or PSPS, the practice in which investor-owned utilities in California de-energize electrical power lines in a defined area when conditions are dry and windy in order to reduce the risk of a power line falling and igniting a wildfire, while power grid upgrades move forward statewide.

Rural and backcountry communities are particularly hard hit when the power is pre-emptively cut off because many homes rely on water from wells powered by electricity for their homes, horses and livestock.

In addition to Ramona, SDG&E has established microgrids in three other areas in High Fire Threat Districts:

The microgrids in Butterfield Ranch and Shelter Valley run on diesel power but the utility plans to complete solar and battery storage systems for each locale by the end of next year, as other regions develop new microgrid rules to guide deployment.

SDG&E has a fifth microgrid in operation — in Borrego Springs, which in 2013 became the first utility-scale microgrid in the country. It provides grid resiliency to the roughly 2,700 residents of the desert town and serves as a model for integrated microgrid projects elsewhere in delivering local electricity. While the Borrego Springs microgrid is not located in a High Fire Threat District, "when and if any power is turned off, especially the power transmission feed that goes to Borrego, we can support the customers using the microgrid out there," Woldemariam said.

Microgrid costs can be higher than conventional energy systems, even as projected energy storage revenue grows over the next decade, and the costs of the SDG&E projects are passed on to ratepayers. As per California Public Utilities Commission rules, the financial details for each of microgrid are kept confidential for at least three years.

SDG&E's microgrids are part of the utility's larger plan to reduce wildfire risk that SDG&E files with the utilities commission. In its wildfire plan for 2020 through 2022, SDG&E expected to spend $1.89 billion on mitigation measures.

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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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Spring Storm Grid Risks highlight tornado outbreaks, flooding, power outages, and transmission disruptions, with NOAA flood outlooks, coal and barge delays, vulnerable nuclear sites, and distribution line damage demanding resilience, reliability, and emergency preparedness.

Key Points

Spring Storm Grid Risks show how tornadoes and floods disrupt power systems, fuel transport, and plants guide resilience.

✅ Tornado outbreaks and derechos damage distribution and transmission

✅ Flooding drives outages via treefall, substation and plant inundation

✅ Fuel logistics disrupted: rail coal, river barges, road access

The storm and tornado outbreak that recently barreled through the US Midwest, South and Mid-Atlantic was a devastating reminder of how much danger spring can deliver, despite it being the “milder” season compared to summer and winter.  

Danger season is approaching, and the country is starting to see the impacts. 

The event killed at least 32 people across seven states. The National Weather Service is still tallying up the number of confirmed tornadoes, which has already passed 100. Communities coping with tragedy are assessing the damage, which so far includes at least 72 destroyed homes in one Tennessee county alone, and dozens more homes elsewhere. 

On Saturday, April 1–the day after the storm struck–there were 1.1 million US utility customers without power, even as EIA reported a January power generation surge earlier in the year. On Monday morning, April 3, there were still more than 80,000 customers in the dark, according to PowerOutage.us. The storm system brought disruptions to both distribution grids–those networks of local power lines you generally see running overhead to buildings–as well as the larger transmission grid in the Midwest, which is far less common than distribution-level issues. 

While we don’t yet have a lot of granular details about this latest storm’s grid impacts, recent shifts in demand like New York City's pandemic power patterns show how operating conditions evolve, and it’s worth going through what else the country might be in for this spring, as well as in future springs. Moreover, there are steps policymakers can take to prepare for these spring weather phenomena and bolster the reliability and resilience of the US power system. 

Heightened flood risk 
The National Oceanic Atmospheric Administration (NOAA) said in a recent outlook that about 44 percent of the United States is at risk of floods this spring, equating to about 146 million people. This includes most of the eastern half of the country, the federal agency said. 

The agency also sees “major” flood risk potential in some parts of the Upper Mississippi River Basin, and relatively higher risk in the Sierra Nevada region, due in part to a historic snowpack in California.  

Multiple components of the power system can be affected by spring floods. 

Power lines – Floods can saturate soil and make trees more likely to uproot and fall onto power lines. This has been contributing to power outages during California’s recent heavy storms–called atmospheric rivers–that started over the winter. In other regions, soil moisture has even been used as a predictor of where power outages will occur due to hurricanes, so that utility companies are better prepared to send line repair crews to the right areas. Hurricanes are primarily a summer and fall phenomenon, and summer also brings grid stress from air conditioning demand in many states, so for now, during spring, they are less of a concern.  

Fuel transport – Spring floods can hinder the transportation of fuels like coal. While it is a heavily polluting fossil fuel that is set to continue declining as a fuel source for US electricity generation, with the EIA summer outlook for wind and solar pointing to further shifts, coal still accounted for roughly 20 percent of the country’s generation in 2022.   

About 70 percent of US coal is transported at least part of the way by trains. The rail infrastructure to transport coal from the Powder River Basin in Montana and Wyoming–the country’s primary coal source–was proven to be vulnerable to extreme floods in the spring of 2011, and even more extreme floods in the spring of 2019. The 2019 floods’ disruptions of coal shipments to power plants via rail persisted for months and into the summertime, also affecting river shipments of coal by barge. In June 2019, hundreds of barges were stalled in the Mississippi River, through which millions of tons of the fossil fuel are normally transported. 

Power plants – Power plants themselves can also be at risk of flooding, since most of them are sited near a source of water that is used to create steam to spin the plants’ turbines, and conversely, low water levels can constrain hydropower as seen in Western Canada hydropower drought during recent reservoir shortfalls. Most US fossil fuel generating capacity from sources like methane gas, which recently set natural gas power records across the grid, and coal utilizes steam to generate electricity. 

However, much of the attention paid to the flood risk of power plant sites has centered on nuclear plants, a key source of low-carbon electricity discussed in IAEA low-carbon electricity lessons that also require a water source for the creation of steam, as well as for keeping the plant cool in an emergency. To name a notable flood example here in the United States–both visually and substantively–in 2011, the Fort Calhoun nuclear plant in Nebraska was completely surrounded by water due to late-spring flooding along the Missouri River. This sparked a lot of concerns because it was just a few months after the March 2011 meltdown of the Fukushima Daiichi nuclear plant in Japan. The public was thankfully not harmed by the Nebraska incident, but this was unfortunately not an isolated incident in terms of flood risks posed to the US nuclear power fleet. 

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Wall Street Fossil Fuel Pivot signals banks reassessing ESG, net-zero, and decarbonization goals, reviving oil, gas, and coal financing while recalibrating clean energy exposure amid policy shifts, regulatory rollbacks, and investment risk realignment.

Key Points

A shift as major U.S. banks ease ESG limits to fund oil, gas, coal while rebalancing alongside renewables.

✅ Banks revisit lending to oil, gas, and coal after policy shifts.

✅ ESG and net-zero commitments face reassessment amid returns.

✅ Renewables compete for capital as risk models are updated.

The global energy finance sector, worth a staggering $1.4 trillion, is undergoing a significant transformation, largely due to former President Donald Trump's renewed support for the oil, gas, and coal industries. Wall Street, which had previously aligned itself with global climate initiatives and the energy transition and net-zero goals, is now reassessing its strategy and pivoting toward a more fossil-fuel-friendly stance.

This shift represents a major change from the earlier stance, where many of the largest U.S. banks and financial institutions took a firm stance on decarbonization push, including limiting their exposure to fossil-fuel projects. Just a few years ago, these institutions were vocal supporters of the global push for a sustainable future, with many committing to support clean energy solutions and abandon investments in high-carbon energy sources.

However, with the change in administration and the resurgence of support for traditional energy sectors under Trump’s policies, these same banks are now rethinking their strategies. Financial institutions are increasingly discussing the possibility of lifting long-standing restrictions that limited their investments in controversial fossil-fuel projects, including coal mining, where emissions drop as coal declines, and offshore drilling. The change reflects a broader realignment within the energy finance sector, with Wall Street reexamining its role in shaping the future of energy.

One of the most significant developments is the Biden administration’s policy reversal, which emphasized reducing the U.S. carbon footprint in favor of carbon-free electricity strategies. Under Trump, however, there has been a renewed focus on supporting the traditional energy sectors. His administration has pushed to reduce regulatory burdens on fossil-fuel companies, particularly oil and gas, while simultaneously reintroducing favorable tax incentives for the coal and gas industries. This is a stark contrast to the Biden administration's efforts to incentivize the transition toward renewable energy and zero-emissions goals.

Trump's policies have, in effect, sent a strong signal to financial markets that the fossil-fuel industry could see a resurgence. U.S. banks, which had previously distanced themselves from financing oil and gas ventures due to the pressure from environmental activists and ESG (Environmental, Social, and Governance) investors, as seen in investor pressure on Duke Energy, are now reconsidering their positions. Major players like JPMorgan Chase and Goldman Sachs are reportedly having internal discussions about revisiting financing for energy projects that involve high carbon emissions, including controversial oil extraction and gas drilling initiatives.

The implications of this shift are far-reaching. In the past, a growing number of institutional investors had embraced ESG principles, with the goal of supporting the transition to renewable energy sources. However, Trump’s pro-fossil fuel stance appears to be emboldening Wall Street’s biggest players to rethink their commitment to green investing. Some are now advocating for a “balanced approach” that would allow for continued investment in traditional energy sectors, while also acknowledging the growing importance of renewable energy investments, a trend echoed by European oil majors going electric in recent years.

This reversal has led to confusion among investors and analysts, who are now grappling with how to navigate a rapidly changing landscape. Wall Street's newfound support for the fossil-fuel industry comes amid a backdrop of global concerns about climate change. Many investors, who had previously embraced policies aimed at curbing the effects of global warming, are now finding it harder to reconcile their environmental commitments with the shift toward fossil-fuel-heavy portfolios. The reemergence of fossil-fuel-friendly policies is forcing institutional investors to rethink their long-term strategies.

The consequences of this policy shift are also being felt by renewable energy companies, which now face increased competition for investment dollars from traditional energy sectors. The shift towards oil and gas projects has made it more challenging for renewable energy companies to attract the same level of financial backing, even as demand for clean energy continues to rise and as doubling electricity investment becomes a key policy call. This could result in a deceleration of renewable energy projects, potentially delaying the progress needed to meet the world’s climate targets.

Despite this, some analysts remain optimistic that the long-term shift toward green energy is inevitable, even if fossil-fuel investments gain a temporary boost. As the world continues to grapple with the effects of climate change, and as technological advancements in clean energy continue to reduce costs, the transition to renewables is likely to persist, regardless of the political climate.

The shift in Wall Street’s approach to energy investments, spurred by Trump’s pro-fossil fuel policies, is reshaping the $1.4 trillion global energy finance market. While the pivot towards fossil fuels may offer short-term gains, the long-term trajectory for energy markets remains firmly in the direction of renewables. The next few years will be crucial in determining whether financial institutions can balance the demand for short-term profitability with their long-term environmental responsibilities.

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Drax Biomass Conversion accelerates renewable energy by replacing coal with wood pellets, sustainable forestry feedstock, and piloting carbon capture and storage, supporting the UK grid, emissions cuts, and a net-zero pathway.

Key Points

Drax Biomass Conversion is Drax's shift from coal to biomass with CCS pilots to cut emissions and aid UK's net-zero.

✅ Coal units converted to biomass wood pellets

✅ Sourced from sustainable forestry residues

✅ CCS pilots target lifecycle emissions cuts

A power station that used to be the biggest polluter in western Europe has made a near-complete switch to renewable energy, mirroring broader shifts as Denmark's largest energy company plans to end coal by 2023.

The Drax Power Station in Yorkshire, England, used to spew out millions of tons of carbon dioxide a year by burning coal. But over the past eight years, it has overhauled its operations by converting four of its six coal-fired units to biomass. The plant's owners say it now generates 15% of the country's renewable power, as Britain recently went a full week without coal power for the first time.

The change means that just 6% of the utility's power now comes from coal, as the wider UK coal share hits record lows across the national electricity system. The ultimate goal is to stop using coal altogether.

"We've probably reduced our emissions more than any other utility in the world by transforming the way we generate power," Will Gardner, CEO of the Drax Group, told CNN Business.

Subsidies have helped finance the switch to biomass, which consists of plant and agricultural matter and is viewed as a promising substitute for coal, and utilities such as Nova Scotia Power are also increasing biomass use. Last year, Drax received £789 million ($1 billion) in government support.

Is biomass good for the environment?

While scientists disagree over the extent to which biomass as a fuel is environmentally friendly, and some environmentalists urge reducing biomass use amid concerns about lifecycle emissions, Drax highlights that its supplies come from from sustainably managed and growing forests.

Most of the biomass used by Drax consists of low-grade wood, sawmill residue and trees with little commercial value from the United States. The material is compressed into sawdust pellets.

Gardner says that by purchasing bits of wood not used for construction or furniture, Drax makes it more financially viable for forests to be replanted. And planting new trees helps offset biomass emissions.

Forests "absorb carbon as they're growing, once they reach maturity, they stop absorbing carbon," said Raphael Slade, a senior research fellow at Imperial College London.

But John Sterman, a professor at MIT's Sloan School of Management, says that in the short term burning wood pellets adds more carbon to the atmosphere than burning coal.

That carbon can be absorbed by new trees, but Sterman says the process can take decades.

"If you're looking at five years, [biomass is] not very good ... If you're looking at a century-long time scale, which is the sort of time scale that many foresters plan, then [biomass] can be a lot more beneficial," says Slade.

Carbon capture

Enter carbon capture and storage technology, which seeks to prevent CO2 emissions from entering the atmosphere and has been touted as a possible solution to the climate crisis.

Drax, for example, is developing a system to capture the carbon it produces from burning biomass. But that could be 10 years away.

The Coal King is racing to avoid bankruptcy

The power station is currently capturing just 1 metric ton of CO2 emissions per day. Gardner says it hopes to increase this to 10,000 metric tons per day by the mid to late 2020s.

"The technology works but scaling it up and rolling it out, and financing it, are going to be significant challenges," says Slade.

The Intergovernmental Panel on Climate Change shares this view. The group said in a 2018 report that while the potential for CO2 capture and storage was considerable, its importance in the fight against climate change would depend on financial incentives for deployment, and whether the risks of storage could be successfully managed. These include a potential CO2 pipeline break.

In the United Kingdom, the government believes that carbon capture and storage will be crucial to reaching its goal of achieving net-zero greenhouse gas emissions by 2050, even as low-carbon generation stalled in 2019 according to industry analysis.

It has committed to consulting on a market-based industrial carbon capture framework and in June awarded £26 million ($33 million) in funding for nine carbon capture, usage and storage projects, amid record coal-free generation on the British grid.

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