Obama admin circulated plan to revamp Energy Dept.

Maritime Electric Hurricane Irma Response details utility crews aiding Turks and Caicos with power restoration, storm recovery, debris removal, and essential services, coordinated with Fortis Inc., despite limited equipment, heat, and over 1,000 downed poles.

Key Points

A utility mission restoring power and essential services in Turks and Caicos after Irma, led by Maritime Electric.

✅ Over 1,000 poles down; crews climbing without bucket trucks

✅ Restoring hospitals, water, and communications first

✅ Fortis Inc. coordination; 2-3 week deployment with follow-on crews

Maritime Electric has sent a crew to help in the clean up and power restoration of Turks and Caicos after the Caribbean island was hit by Hurricane Irma, a storm that also saw FPL's massive response across Florida.

They arrived earlier this week and are working on removing debris and equipment so when supplies arrive, power can be brought back online, and similar mutual aid deployments, including Canadian crews to Florida, have been underway as well.

Fortis Inc., the parent company for Maritime Electric operates a utility in Turks and Caicos.

Kim Griffin, spokesperson for Maritime Electric, said there are over 1000 poles that were brought down by the storm, mirroring Florida restoration timelines reported elsewhere.

"It's really an intense storm recovery," she said. 'Good spirits'

The crew is working with less heavy equipment than they are used to, climbing poles instead of using bucket trucks, in hot and humid weather.

Griffin said their focus is getting essential services restored as quckly as possible, similar to progress in Puerto Rico's restoration efforts following recent hurricanes.

The crew will be there for two or three weeks and Griffin said Maritime Electric may send another group, as seen with Ontario's deployment to Florida, to continue the job.

She said the team has been well received and is in "good spirits."

"The people around them have been very positive that they're there," she said.

"They've said it's just been overwhelming how kind and generous the people have been to them."

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China Energy Crisis drives electricity shortages, power cuts, and blackouts as coal prices surge, carbon-neutrality rules tighten, and manufacturing hubs ration energy, disrupting supply chains and industrial output ahead of winter demand peaks.

Key Points

A power shortfall from costly coal, price caps, and emissions targets, causing blackouts and industrial rationing.

✅ Coal prices soar while electricity tariffs are capped

✅ Factories in northeast hubs face rationing and downtime

✅ Supply chains risk delays ahead of winter demand

China is struggling with a severe shortage of electricity which has left millions of homes and businesses hit by power cuts.

Blackouts are not that unusual in the country but this year a number of factors have contributed to a perfect storm for electricity suppliers, including surging electricity demand globally.

The problem is particularly serious in China's north eastern industrial hubs as winter approaches - and is something that could have implications for the rest of the world.

Why has China been hit by power shortages?
The country has in the past struggled to balance electricity supplies with demand, which has often left many of China's provinces at risk of power outages.

During times of peak power consumption in the summer and winter the problem becomes particularly acute.

But this year a number of factors have come together to make the issue especially serious.

As the world starts to reopen after the pandemic, demand for Chinese goods is surging and the factories making them need a lot more power, highlighting China's electricity appetite in recent months.

Rules imposed by Beijing as it attempts to make the country carbon neutral by 2060 have seen coal production slow, even as the country still relies on coal for more than half of its power and as low-emissions generation is set to cover most global demand growth.

And as electricity demand has risen, the price of coal has been pushed up.

But with the government strictly controlling electricity prices, coal-fired power plants are unwilling to operate at a loss, with many drastically reducing their output instead.

Who is being affected by the blackouts?
Homes and businesses have been affected by power cuts as electricity has been rationed in several provinces and regions.

A coal-burning power plant can be seen behind a factory in China"s Inner Mongolia Autonomous Region

The state-run Global Times newspaper said there had been outages in four provinces - Guangdong in the south and Heilongjiang, Jilin and Liaoning in the north east. There are also reports of power cuts in other parts of the country.

Companies in major manufacturing areas have been called on to reduce energy usage during periods of peak demand or limit the number of days that they operate.

Energy-intensive industries such as steel-making, aluminium smelting, cement manufacturing and fertiliser production are among the businesses hardest hit by the outages.

What has the impact been on China's economy?
Official figures have shown that in September 2021, Chinese factory activity shrunk to the lowest it had been since February 2020, when power demand dropped as coronavirus lockdowns crippled the economy.

Concerns over the power cuts have contributed to global investment banks cutting their forecasts for the country's economic growth.

Goldman Sachs has estimated that as much as 44% of the country's industrial activity has been affected by power shortages. It now expects the world's second largest economy to expand by 7.8% this year, down from its previous prediction of 8.2%.

Globally, the outages could affect supply chains, including solar supply chains as the end-of-the-year shopping season approaches.

Since economies have reopened, retailers around the world have already been facing widespread disruption amid a surge in demand for imports.

China's economic planner, the National Development and Reform Commission (NDRC), has outlined a number of measures to resolve the problem, with energy supplies in the northeast of the country as its main priority this winter.

The measures include working closely with generating firms to increase output, ensuring full supplies of coal and promoting the rationing of electricity.

The China Electricity Council, which represents generating firms, has also said that coal-fired power companies were now "expanding their procurement channels at any cost" in order to guarantee winter heat and electricity supplies.

However, finding new sources of coal imports may not be straightforward.

Russia is already focused on its customers in Europe, Indonesian output has been hit by heavy rains and nearby Mongolia is facing a shortage of road haulage capacity,

Are energy shortages around the world connected?
Power cuts in China, UK petrol stations running out of fuel, energy bills jumping in Europe, near-blackouts in Japan and soaring crude oil, natural gas and coal prices on wholesale markets - it would be tempting to assume the world is suddenly in the grip of a global energy drought.

However, it is not quite as simple as that - there are some distinctly different issues around the world.

For example, in the UK petrol stations have run dry as motorists rushed to fill up their vehicles over concerns that a shortage of tanker drivers would mean fuel would soon become scarce.

Meanwhile, mainland Europe's rising energy bills and record electricity prices are due to a number of local factors, including low stockpiles of natural gas, weak output from the region's windmills and solar farms and maintenance work that has put generating operations out of action.
 

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U.S. Power Grid D+ Rating underscores aging infrastructure, rising outages, cyber threats, EMP and solar flare risks, strained transmission lines, vulnerable transformers, and slow permitting, amplifying reliability concerns and resilience needs across national energy systems.

Key Points

ASCE's D+ grade flags aging infrastructure, rising outages, and cyber, EMP, and weather risks needing investment.

✅ Major outages rising; weather remains top disruption driver.

✅ Aging transformers, transmission lines, limited maintenance.

✅ Cybersecurity gaps via smart grid, EV charging, SCADA.

The U.S. power grid just received its “grade card” from the American Society of Civil Engineers (ASCE) and it barely passed.

The overall rating of our antiquated electrical system was a D+. Major power outages in the United States, including widespread blackouts, have grown from 76 in 2007 to 307 in 2011, according to the latest available statistics. The major outage figures do not take into account all of the smaller outages which routinely occur due to seasonal storms.

The American Society of Civil Engineers power grid grade card rating means the energy infrastructure is in “poor to fair condition and mostly below standard, with many elements approaching the end of their service life.” It further means a “large portion of the system exhibits significant deterioration” with a “strong risk of failure.”

Such a designation is not reassuring and validates those who purchased solar generators over the past several years.

#google#

The vulnerable state of the power grid gets very little play by mainstream media outlets. Concerns about a solar flare or an electromagnetic pulse (EMP) attack instantly sending us back to an 1800s existence are legitimate, but it may not take such an extreme act to render the power grid a useless tangle of wires. The majority of the United States’ infrastructure and public systems evaluated by the ASCE earned a “D” rating. A “C” ranking (public parks, rail and bridges) was the highest grade earned. It would take a total of $3.6 trillion in investments by 2020 to fix everything, the report card stated. To put that number in perspective, the federal government’s budget for all of 2012 was slightly more, $3.7 trillion.

“America relies on an aging electrical grid and pipeline distribution systems, some of which originated in the 1880s,” the report read. “Investment in power transmission has increased since 2005, but ongoing permitting issues, weather events, including summer blackouts that strain local systems, and limited maintenance have contributed to an increasing number of failures and power interruptions. While demand for electricity has remained level, the availability of energy in the form of electricity, natural gas, and oil will become a greater challenge after 2020 as the population increases. Although about 17,000 miles of additional high-voltage transmission lines and significant oil and gas pipelines are planned over the next five years, permitting and siting issues threaten their completion. The electric grid in the United States consists of a system of interconnected power generation, transmission facilities, and distribution facilities.”

Harness the power of the sun when the power goes out…

There are approximately 400,000 miles of electrical transmission lines throughout the United States, and thousands of power generating plants dot the landscape. The ASCE report card also stated that new gas-fired and renewable generation issues increase the need to add new transmission lines. Antiquated power grid equipment has reportedly prompted even more “intermittent” power outages in recent years.

The American Society of Civil Engineers accurately notes that the power grid is more vulnerable to cyber attacks than ever before, including Russian intrusions documented in recent years, and it cites the aging electrical system as the primary culprit. Although the decades-old transformers and other equipment necessary to keep power flowing around America are a major factor in the enhanced vulnerability of the power grid, moving towards a “smart grid” system is not the answer. As previously reported by Off The Grid News, smart grid systems and even electric car charging stations make the power grid more accessible to cyber hackers. During the Hack in the Box Conference in Amsterdam, HP ArcSight Product Manager Ofer Sheaf stated that electric car charging stations are in essence a computer on the street. The roadway fueling stations are linked to the power grid electrical system. If cyber hackers garner access to the power grid via the charging stations, they could stop the flow of power to a specific area or alter energy distribution levels and overload the system.

While a relatively small number of electric car charging stations exist in America now, that soon will change. Ongoing efforts by both federal and state governments to reduce our reliance on fossil fuels have resulted in grants and privately funded vehicle charging station projects. New York Governor Andrew Cuomo in April announced plans to build 360 such electrical stations in his state. A total of 3,000 car charging stations are in the works statewide and are slated for completion over the next five years.

SHIELD ActWeather-related events were the primary cause of power outages from 2007 to 2012, according to the infrastructure report card. Power grid reliability issues are emerging as the greatest threat to the electrical system, with rising attacks on substations compounding the risks. The ASCE grade card also notes that retiring and rotating in “new energy sources” is a “complex” process. Like most items we routinely purchase in our daily lives, many of the components needed to make the power grid functional are not manufactured in the United States.

The SHIELD Act is the first real piece of federal legislation in years drafted to address power grid vulnerabilities. While the single bill will not fix all of the electrical system issues, it is a big step in the right direction – if it ever makes it out of committee. Replacing aging transformers, encasing them in a high-tech version of a Faraday cage, and stockpiling extra units so instant repairs are possible would help preserve one of the nation’s most critical and life-saving pieces of infrastructure after a weather-related incident or man-made disaster.

“Geomagnetic storm environments can develop instantaneously over large geographic footprints,” solar geomagnetic researcher John Kappenman said about the fragile state of the power grid. He was quoted in an Oak Ridge National Laboratory report. “They have the ability to essentially blanket the continent with an intense threat environment and … produce significant collateral damage to critical infrastructures. In contrast to well-conceived design standards that have been successfully applied for more conventional threats, no comprehensive design criteria have ever been considered to check the impact of the geomagnetic storm environments. The design actions that have occurred over many decades have greatly escalated the dangers posed by these storm threats for this critical infrastructure.”

The power grid has morphed in size tenfold during the past 50 years. While solar flares, cyber attacks, and an EMP are perhaps the most extensive and frightening threats to the electrical system, the infrastructure could just as easily fail in large portions due to weather-related events exacerbated by climate change across regions. The power grid is basically a ticking time bomb which will spawn civil unrest, lack of food, clean water, and a multitude of fires if it does go down.

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Twin States Clean Energy Link connects New England to Hydro-Quebec via a 1,200 MW transmission line, DOE-backed capacity, underground segments, existing corridors, boosting renewable energy reliability across Vermont and New Hampshire with cross-border grid flexibility.

Key Points

DOE-backed 1,200 MW line linking Hydro-Quebec to New England, adding clean capacity with underground routes.

✅ 1,200 MW cross-border capacity for the New England grid

✅ Uses existing corridors; underground in VT and northern NH

✅ DOE capacity contract lowers risk and spurs investment

A proposal to build a new transmission line to connect New England with Canadian hydropower is one step closer to reality.

The U.S. Department of Energy announced Monday that it has selected the Twin States Clean Energy Link as one of three transmission projects that will be part of its $1.3 billion cross-border transmission initiative to add capacity to the grid.

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Twin States is a proposal from National Grid, a utility company that serves Massachusetts, New York, and Rhode Island, and also owns transmission in England and Wales as the region advances projects like the Scotland-to-England subsea link that expand renewable flows, and the non-profit Citizens Energy Corporation.

The transmission line would connect New England with power from Hydro-Quebec, moving into the United States from Canada in Northern Vermont and crossing into New Hampshire near Dalton. It would run through parts of Grafton, Merrimack, and Hillsborough counties, routing through a substation in Dunbarton and ending at a proposed new substation in Londonderry. (Here's a map of the Twin States proposal.)

The federal funding will allow the U.S. Department of Energy to purchase capacity on the planned transmission line, which officials say reduces the risk for other investors and can help encourage others to purchase capacity.

The project has gotten support from local officials in Vermont and New Hampshire, but there are still hurdles to cross. The contract negotiation process is beginning, National Grid said, and the proposal still needs approvals from regulators before construction could begin.

First Nations communities in Canada have opposed transmission lines connecting Hydro-Quebec with New England in the past, and the company has faced scrutiny from environmental groups.

What would Twin States look like?
Transmission projects, like the failed Northern Pass proposal, have been controversial in New England, though the Great Northern Transmission Line progressed in Minnesota.

But Reihaneh Irani-Famili, vice president of capital delivery, project management and construction at National Grid, said this one is different because the developers listened to community concerns before planning the project.

“They did not want new corridors of infrastructure, so we made sure that we're using existing right of way,” she said. “They did not want the visual impact and some of the newer corridors of infrastructure, we're making sure we're undergrounding portions of the line.”

In Vermont and northern New Hampshire, the transmission lines would be buried underground along state roads. South of Littleton, they would be located within existing transmission corridors.

The developers say the lines could provide 1,200 megawatts of transmission capacity. The project would have the ability to carry electricity from hydro facilities in Quebec to New England, and would also be able to bring electricity from New England into Quebec, a step toward broader macrogrid connectivity across regions.

“Those hydro dams become giant green batteries for the region, and they hold that water until we need the electrons,” Irani-Famili said. “So if you think about our energy system not as one that sees borders, but one that sees resources, this is connecting the Quebec resources to the New England resources and helping all of us get into that cleaner energy future with a lot less build than we otherwise would have.”

Irani-Famili says the transmission line could help facilitate more clean energy resources like offshore wind coming online. In a report released last week by New Hampshire’s Department of Energy, authors said importing Canadian hydropower could be one of the most cost-effective ways to move away from fossil fuels on the electric grid.

National Grid estimates the project will help save energy customers $8.3 billion in its first 12 years. The developers are constructing a $260 million “community benefits plan” that would take some profits from the transmission line and give that money back to communities that host the transmission lines and environmental justice communities in New England.

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PG&E Wind Shutdown and Renewable Reliability examines PSPS strategy, wildfire risk, transmission line exposure, wind turbine cut-out speeds, grid stability, and California's energy mix amid historic high-wind events and supply constraints across service areas.

Key Points

An overview of PG&E's PSPS decisions, wildfire mitigation, and how wind cut-out limits influence grid reliability.

✅ Wind turbines reach cut-out near 55 mph, reducing generation.

✅ PSPS mitigates ignition from damaged transmission infrastructure.

✅ Baseload diversity improves resilience during high-wind events.

According to the official, widely reported story, Pacific Gas & Electric (PG&E) initiated power shutoffs across substantial portions of its electric transmission system in northern California as a precautionary measure.

Citing high wind speeds they described as “historic,” the utility claims that if it didn’t turn off the grid, wind-caused damage to its infrastructure could start more wildfires.

Perhaps that’s true. Perhaps. This tale presumes that the folks who designed and maintain PG&E’s transmission system are unaware of or ignored the need to design it to withstand severe weather events, and that the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) allowed the utility to do so.

Ignorance and incompetence happens, to be sure, but there’s much about this story that doesn’t smell right—and it’s disappointing that most journalists and elected officials are apparently accepting it without question.

Take, for example, this statement from a Fox News story about the Kincade Fires: “A PG&E meteorologist said it’s ‘likely that many trees will fall, branches will break,’ which could damage utility infrastructure and start a fire.”

Did you ever notice how utilities cut wide swaths of trees away when transmission lines pass through forests? There’s a reason for that: When trees fall and branches break, the grid can still function, and even as the electric rhythms of New York City shifted during COVID-19, operators planned for variability.

So, if badly designed and poorly maintained infrastructure isn’t the reason PG&E cut power to millions of Californians, what might have prompted them to do so? Could it be that PG&E’s heavy reliance on renewable energy means they don’t have the power to send when a “historic” weather event occurs, especially as policymakers weigh the postponed closure of three power plants elsewhere in California?

Wind Speed Limits

The two most popular forms of renewable energy come with operating limitations, which is why some energy leaders urge us to keep electricity options open when planning the grid. With solar power, the constraint is obvious: the availability of sunlight. One doesn’t generate solar power at night and energy generation drops off with increasing degrees of cloud cover during the day.

The main operating constraint of wind power is, of course, wind speed, and even in markets undergoing 'transformative change' in wind generation, operators adhere to these technical limits. At the low end of the scale, you need about a 6 or 7 miles-per-hour wind to get a turbine moving. This is called the “cut-in speed.” To generate maximum power, about a 30 mph wind is typically required. But, if the wind speed is too high, the wind turbine will shut down. This is called the “cut-out speed,” and it’s about 55 miles per hour for most modern wind turbines.

It may seem odd that wind turbines have a cut-out speed, but there’s a very good reason for it. Each wind turbine rotor is connected to an electric generator housed in the turbine nacelle. The connection is made through a gearbox that is sized to turn the generator at the precise speed required to produce 60 Hertz AC power.

The blades of the wind turbine are airfoils, just like the wings of an airplane. Adjusting the pitch (angle) of the blades allows the rotor to maintain constant speed, which, in turn, allows the generator to maintain the constant speed it needs to safely deliver power to the grid. However, there’s a limit to blade pitch adjustment. When the wind is blowing so hard that pitch adjustment is no longer possible, the turbine shuts down. That’s the cut-out speed.

Now consider how California’s power generation profile has changed. According to Energy Information Administration data, the state generated 74.3 percent of its electricity from traditional sources—fossil fuels and nuclear, amid debates over whether to classify nuclear as renewable—in 2001. Hydroelectric, geothermal, and biomass-generated power accounted for most of the remaining 25.7 percent, with wind and solar providing only 1.98 percent of the total.

By 2018, the state’s renewable portfolio had jumped to 43.8 percent of total generation, with clean power increasing and wind and solar now accounting for 17.9 percent of total generation. That’s a lot of power to depend on from inherently unreliable sources. Thus, it wouldn’t be at all surprising to learn that PG&E didn’t stop delivering power out of fear of starting fires, but because it knew it wouldn’t have power to deliver once high winds shut down all those wind turbines

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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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