Electricity News in April 2021
In a record year for clean energy purchases, Southeast cities stand out
Municipal Renewable Energy Procurement surged as cities contracted 3.7 GW of solar and wind, leveraging green tariffs, community solar, and utility partnerships across the Southeast, led by Houston, RMI, and WRI data.
Key Points
The process by which cities contract solar and wind via utilities or green tariffs to meet climate goals.
✅ 3.7 GW procured in 2020, nearly 25% year-over-year growth
✅ Houston runs city ops on 500 MW solar, a record purchase
✅ Southeast cities use green tariffs and community solar
Cities around the country bought more renewable energy last year than ever before, reflecting how renewables may soon provide one-fourth of U.S. electricity across the grid, with some of the most remarkable projects in the Southeast, according to new data unveiled Thursday.
Even amid the pandemic, about eight dozen municipalities contracted to buy nearly 3.7 gigawatts of mostly solar and wind energy — enough to power more than 800,000 homes. The figure is almost a quarter higher than the year before.
Half of the cites listed as “most noteworthy” in Thursday’s release — from research groups Rocky Mountain Institute and World Resources Institute — are in the region that stretches from Texas to Washington, D.C.
Houston stands out for the sheer enormity of its purchase: In July, it began powering city operations entirely from nearly 500 megawatts of solar power — the largest municipal purchase of renewable energy ever in the United States, as renewable electricity surpassed coal nationwide.
The groups also feature smaller deals in North Carolina and Tennessee, achieved through a utility partnership called a green tariff.
“We wanted to recognize that Nashville and Charlotte were really blazing a new trail,” said Stephen Abbott, principal at the Rocky Mountain Institute.
And the nation’s capital shows how renewable energy can be a source of revenue: It’s leasing out its public transit station rooftops for 10 megawatts of community solar.
All of these strategies will be necessary for scores of U.S. cities to meet their ambitious climate goals, researchers believe. An interactive clean energy targets tracker shows all 95 clean energy procurements from the year in detail.
Tracker
Even before former President Donald Trump promised to remove the United States from the Paris Climate Accord, a lack of federal action on climate left a void that some cities and counties were beginning to fill, as renewables hit a record 28% in a recent month. In 2015, the first year tracked by researchers at the Rocky Mountain Institute and the World Resources Institute, municipalities contracted to buy more than 1 gigawatt of wind, solar and other forms of clean energy.
But when Trump officially set in motion the withdrawal from the climate agreement, the ranks of municipalities dedicated to 100% clean energy multiplied. Today there are nearly 200 of them. The growth in activity last year reflects, in part, that surge of new pledges.
“It takes a while to get city staff up to speed and understand the options, and create the roadmap and then start executing,” Abbott said. “There is a bit of a lag, but we’re starting to see the impact.”
Even in Houston — one of the earliest to begin procuring renewable energy — there has been a steep learning curve as market forces change and prices drop, including cheaper solar batteries shaping procurement strategies, said Lara Cottingham, Houston’s chief of staff and chief sustainability officer.
No matter how well resourced and educated their staff, cities have to clear a thicket of structural, political and economic challenges to procure renewable energy. Most don’t own their own sources of power. Nearly all face budget constraints. Few have enough land or government rooftops to meet their goals within city limits.
“Cities face a situation where it’s a square peg in a round hole,” Cottingham said.
The hurdles are especially steep in much of the Southeast, where only publicly regulated utilities can sell electricity to retail customers, even large ones such as major cities. That’s where a green tariff regime comes in: Cities can purchase clean energy from a third party, such as a solar company, using the utility as a go-between.
Early last year, Charlotte became the largest city to use such a program, partnering with Duke Energy and two North Carolina solar developers to build a solar farm 50 miles north in Iredell County. At first, the city will pay a premium for the energy, but in the latter half of the 20-year contract, as gas prices rise, it will save money compared to business as usual.
“Over the course of 20 years, it’s projected we would save about $2 million,” Katie Riddle, sustainability analyst with Charlotte, told the Energy News Network last year.
The growing size of projects, innovative partnerships like green tariff programs, and the improving economics all give Abbott hope that renewable energy investments from cities will only grow — even with the Trump presidency over and the country back in the Paris agreement.
And when cities meet their goals for procuring renewable energy for their own operations, they must then turn to an even bigger task: reducing the carbon footprint of every person in their jurisdiction with broader decarbonization strategies and community engagement.
“The city needs to do its part for sure,” said Houston’s Cottingham. “Then we have this challenge of how do we get everyone else to.”
Related News
California looks to electric vehicles for grid stability
California EV V2G explores bi-directional charging, smart charging, and demand response to enhance grid reliability. CPUC, PG&E, and automakers test incentives aligning charging with solar and wind, helping prevent blackouts and curtailment.
Key Points
California EV V2G uses two-way charging and smart incentives to support grid reliability during peak demand.
✅ CPUC studies feasibility, timelines, and cost barriers to V2G
✅ Incentives shift charging to align with solar, wind, off-peak hours
✅ High-cost bidirectional chargers and warranties remain hurdles
California energy regulators are eyeing the power stored in electric vehicles as they hunt for ways to avoid blackouts caused by extreme weather.
While few EV and their charging ports are equipped to deliver electricity back into the grid during emergencies, the California Public Utilities Commission wants more data on it as the agency rules on steps utilities must take to ensure they have enough power for this summer and next year. A draft CPUC decision due to be discussed this week asks about the feasibility of reversing the charge when needed (Energywire, March 8).
“Very few [EVs], maybe a couple of thousand at the most, can give power to the grid, and even fewer are connected into a charger that can do it,” said Gil Tal, director of the Plug-in Hybrid & Electric Vehicle Research Center at the University of California, Davis. EVs that feature the ability “have it at a more experimental level.”
The issue arises as California, where about half of all U.S. EVs are purchased, examines what role the vehicles can play in keeping lights on and refrigerators running and how a much bigger grid will support them in the long term. Even if grid operators can’t pull from EV batteries en masse, experts say cash and other incentives can prompt drivers to shift charging times, boosting grid stability.
“What we can do is not charge the electric cars at times of high demand” such as during heat waves, Tal said.
The EV focus comes after California’s grid manager last summer imposed rolling blackouts when power supplies ran short during a record-shattering heat wave. State energy regulators across the U.S., as EVs challenge state grids, are also looking at their disaster preparedness as Texas recovers from a winter storm last month that cut off electricity for more than 4 million homes and businesses there.
California’s EV efforts can help other states as they add more renewable power to their grids, said Adam Langton, energy services manager at BMW of North America.
That automaker ran a pilot program with San Francisco-based utility Pacific Gas & Electric Co. (PG&E) looking at whether money and other incentives could prompt EV drivers to charge their cars at different times. The payments successfully shifted charging to the middle of the night, when wind power often is plentiful. It also moved some repowering to mornings and early afternoons, when there’s abundant solar energy.
“That can be a tool that the utilities can use to deal with supply issues,” Langton said. “What our research has shown is that vehicles can contribute to [conservation] needs and emergency supply by shifting their charging time.”
Such measures can also help states avoid having to curtail solar production on days when there’s more generation than needed. On many bright days, California has more solar power than it can use.
“As more states add more renewable energy, we think that they’re going to find that EVs complement that really well with smart charging, because grid coordination can get that charging to align with the renewable energy,” Langton said. “It allows to add more and more renewable energy.”
High-cost equipment a hurdle
The CPUC at a future workshop plans to collect information on leveraging EVs to head off power shortages at key times.
But Tal said it will probably take a decade to get enough EVs capable of exporting electricity back to utilities “in high numbers that can make an impact on the grid.”
Barriers to reaching such “vehicle to grid” integration are technical and economic, he said. EVs export direct current and need a device on the other side that can convert it to alternating current, similar to a solar power inverter for rooftop panels.
However, the equipment known as a V2G capable charger is costly. It ranges from $4,500 to $5,500, according to a 2017 National Renewable Energy Laboratory report.
PG&E and Los Angeles-based Southern California Edison already have “expressed doubt that short-term measures could be developed in time to expand EV participation by summer 2021” in V2G programs, the draft CPUC proposal said. The utilities suggested instead that the agency encourage EV owners to participate in initiatives where they’d get paid for reducing power consumption or sell electricity back to the grid when needed, known as demand response programs.
Still, almost all major EV automakers are looking at two-directional charging, Tal said.
“The incentive is you can get more value for the car,” he said. “The disincentive is you add more miles in a way on the car,” because an owner would be discharging to the grid and re-charging, and “the battery has limited life.”
And right now, discharging a vehicle to the grid would violate many warranties, he said. Car manufacturers would need to agree to change that and could call for compensation in return.
Meanwhile, San Diego Gas & Electric Co., a Sempra Energy subsidy, plans to launch a pilot looking at delivering power to the grid from electric school buses. The six buses in the pilot transport students in El Cajon, Calif., east of San Diego.
“The buses are perfect because of their big batteries and predictable schedule,” Jessica Packard, SDG&E spokesperson, said in an email. “Ultimately, we hope to scale up and deploy these kinds of innovations throughout our grid in the future.”
She declined to say how much power the buses could deliver because the project isn’t yet operating. It’s set to start later this year.
Mobility needs
While BMW and PG&E did not review vehicle-to-grid power transfers in their own 2017 research ending last year, one study in Delaware did. But it was in a university setting about eight years ago and didn’t look at actual drivers, said Langton with BMW.
In their own findings from the San Francisco Bay Area pilot program, BMW and PG&E found that incentives could quickly change driver behavior in terms of charging.
Technology helps: Most new EVs have timers that allow the driver to control when to charge and when to stop charging. Langton said the pilot program got drivers to have their cars charge from roughly 2 to 6 a.m., when electricity rates typically are lowest.
There can be a lot of solar energy during the day, but in summer, optimum charging times get more complicated in California, he said. People want to run their air conditioners during peak heat hours, so it’s important to be able to get EV drivers to shift to less congested times, he said.
With the right incentives or messaging, Langton said, the pilot persuaded drivers to move charging from 10 a.m. to 2 p.m. or noon to 4 p.m. BMW technology allowed for detailed information on battery charge level, ideal charging times and other EV data to be transmitted electronically after plugging in.
The findings are a good first step toward future vehicle-to-grid integration, Langton added.
“One of the things we really pay attention to when we do smart charging is, ‘How does the driver’s mobility needs figure into shifting their charging?'” he said. “We want to make sure that our customers can always do the driving that they need to do.”
The pilot included safeguards such as an opt-out button if the driver wanted to charge immediately. It also made sure the vehicle had a certain level of minimum charge — 15% to 20% — before the delayed smart charging kicked in.
Vehicle-to-grid technology would need to wrestle with the same concepts in a different way. If a car is getting discharged, the driver would want assurances its battery wouldn’t dip below a level that meets their mobility needs, Langton said.
“If that happened even once to a customer, they would probably not want to participate in these programs in the future,” he said.
One group adding charging stations across the country said it isn’t tweaking pricing based on when drivers charge. That’s to help grow EV purchases, said Robert Barrosa, senior director of sales and marketing at Volkswagen AG subsidiary Electrify America, which operates about 450 charging stations in 45 states.
The company has installed battery storage at more than 100 sites to make sure they can provide power at consistent prices even if California or another state calls for energy conservation.
“It’s very important for vehicle adoption that the customer have that,” Barrosa said.
The company could sell that battery storage back to the grid if there are shortfalls, but some market changes are needed first, particularly in California, he said. That’s because the company buys electricity on the retail side but would be sending it back into the wholesale market.
With that cost differential, Barrosa said, “it doesn’t make sense.”
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New England's solar growth is creating tension over who pays for grid upgrades
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.”
Related News
Michigan solar supporters make new push to eliminate rooftop solar caps
Michigan Distributed Energy Cap Repeal advances a bipartisan bill to boost rooftop solar and net metering, countering DTE and Consumers Energy claims, expanding energy freedom, jobs, and climate resilience across investor-owned utility territories.
Key Points
A Michigan bill to remove the 1% distributed energy cap, expanding rooftop solar, net metering, and clean energy jobs.
✅ Removes 1% distributed generation cap statewide
✅ Supports rooftop solar, net metering, and job growth
✅ Counters utility cost-shift claims with updated tariffs
A bipartisan group of Michigan lawmakers has introduced legislation to eliminate a 1% cap on distributed energy in the state’s investor-owned utility territories.
It’s the third time in recent years that such legislation has been introduced. Though utilities and their political allies have successfully blocked it to date, through tactics some critics say reflect utilities tilting the solar market by incumbents, advocates see an opportunity with a change in state Republican caucus leadership and Michigan’s burgeoning solar industry approaching the cap in some utility territories.
The bill also has support from a broad swath of legislators for reasons having to do with job creation, energy freedom and the environment, amid broader debates over states' push for renewables and affordability. Already the bill has received multiple hearings, even as DTE Energy and Consumers Energy, Michigan’s largest private utilities, are ramping up attacks in an effort to block the bill.
“It’s going to be vehemently opposed by the utilities but there are only benefits to this if you are anybody but DTE,” said Democratic state Rep. Yousef Rabhi, who cosigned HB 4236 and has helped draft language in previous bills. “If we remove the cap, then we’re putting the public’s interest first, and we’re putting DTE’s interest first if we keep the cap in place.”
The Michigan Legislature enacted the cap as part of a sweeping 2016 energy bill that clean energy advocates say included a number of provisions that have kneecapped the small-scale distributed energy industry, particularly home solar. The law caps distributed energy production at 1% of a utility’s average in-state peak load for the past five years.
Republicans have controlled the Legislature and committees since the law was enacted, amid parallel moves such as the Wyoming clean energy bill in another state, and previous attempts to cut the language haven’t received House committee hearings. However, former Republican House leader Lee Chatfield has been replaced, and already the new bill, introduced by Republican state Rep. Gregory Markkanen, the energy committee’s vice chair, has had two hearings.
Previous attempts to cut the language were also a part of a larger package of bills, and this time around the bill is a standalone. The legislation is also moving as Consumers and Upper Peninsula Power Co. have voluntarily doubled their cap to two percent, which advocates say highlights the need to repeal the cap .
Rabhi said there’s bipartisan support because many conservatives and progressives view it as an infringement on customers’ energy freedom since the cap will eventually effectively prohibit new distributed energy generation. Legislators say the existing law kills jobs because it severely limits the clean energy industry’s growth, and Rabhi said he’s also strongly motivated by increasing renewable energy production to address climate change.
In February, Michigan Public Service Commission Chairman Dan Scripps testified to the House committee, with observers also pointing to FERC action on aggregated DERs as relevant context, that the commission is “supportive in taking steps to ensure solar developers in Michigan are able to continue operating and thus support in concept the idea of lifting or eliminating the cap” in order to protect the home solar industry.
The state’s solar industry has long criticized the cap, and removing it is a “no brainer,” said Dave Strenski, executive director of Solar Ypsi, which promotes rooftop solar in Ypsilanti.
“If they have a cap and we reach that cap, then rooftop solar is shut down in Michigan,” he said. “The utilities don’t mind solar as long as they own it, and that’s what it boils down to.”
The state’s utilities see the situation differently. Spokespeople for DTE and Consumers told the Energy News Network that lifting the cap would shift the cost burden of maintaining their territory-wide infrastructure from all customers to low income customers who can’t afford to install solar panels, often invoking reliability examples such as California's reliance on fossil generation to justify caution.
The bill “doesn’t address the subsidy certain customers are paid at the expense of those who cannot afford to put solar panels on their homes,” said Katie Carey, Consumers Energy’s spokesperson.
However, clean energy advocates argue that studies have found that to be untrue. And even if it were true, Rabhi said, the utilities told lawmakers in 2016 that a new inflow/outflow tariff that the companies successfully pushed for to replace net metering dramatically reduced compensation for home solar users and would address that inequality.
“DTE’s and Consumers’ own argument is that by making that change, distributed generation is no longer a ‘burden’ on low income customers, so now we have inflow/outflow and the problem should be solved,” Rabhi said.
He added that claims that DTE and Consumers are looking out for low-income customers are disingenuous because they have repeatedly fought larger allowances for programs that help those customers, and refuse to “dip into their massive corporate profits and make sure poor people don’t have to pay as much for electricity.”
“I don’t want to hear a sob story from DTE about how putting solar panels on the house is going to hurt poor people,” he said. “That is entirely the definition of hypocrisy — that’s the utilities using poor people as a pawn and that’s why people are sick of these corporations.”
The companies have already begun their public relations attack designed to help thwart the bill. DTE and Consumers spread money generously among Republicans and Democrats in the Legislature each cycle, and the two companies’ dark money nonprofits launched a round of ads targeting Democratic lawmakers, reflecting the broader solar wars playing out nationally. Several sit on the House Energy Committee, which must approve the bill before it can go in front of the full Legislature.
The DTE-backed Alliance For Michigan Power and Consumers Energy-funded Citizens Energizing Michigan’s Economy have purchased dozens of Facebook ads alluding to action by the legislators, though there hasn’t been a vote.
Facebook ads aren’t uncommon as they get “bang for their buck,” said Matt Kasper, research director with utility industry watchdog Energy And Policy Institute. Already hundreds of thousands of people have potentially viewed the ads and the groups have only spent thousands of dollars. The ads are likely designed to get Facebook users to interact with the legislators on the issue, Kasper said, even if there’s little information in the ad, and the info in the ad that does exist is highly misleading.
DTE and Consumers spokespersons declined to comment on the spending and directed questions to the dark money nonprofits. No one there could be reached for comment.
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Texas's new set of electricity regulators begins to take shape in wake of deep freeze, power outages
Texas PUC Appointments signal post-storm reform as Gov. Greg Abbott taps Peter Lake and advances Will McAdams for Senate confirmation, affecting ERCOT oversight, grid reliability, wholesale power pricing, and securitization for co-ops.
Key Points
Texas PUC appointments add Peter Lake and Will McAdams to steer ERCOT, grid reliability, and market policy.
✅ Peter Lake nominated chair to replace Arthur D'Andrea.
✅ Will McAdams advances toward Senate confirmation.
✅ Focus on ERCOT oversight, price cap debate, grid resilience.
A new set of Texas electricity regulators began to take shape Monday, as Gov. Greg Abbott nominated a finance expert to be the next chairman of the Public Utility Commission while his earlier choice of a PUC member moved toward Senate confirmation.
The Republican governor put forward Peter Lake of Austin, who has spent more than five years as an Abbott appointee to the Texas Water Development Board, as his second commission pick in as many weeks.
“I am confident he will bring a fresh perspective and trustworthy leadership to the PUC,” Abbott said of Lake, who once worked as a trader of futures and derivatives for a firm belonging to the Chicago Mercantile Exchange and more recently has eagerly promoted bonds for the State Water Implementation Fund for Texas.
“Peter’s expertise in the Texas energy industry and business management will make him an asset to the agency,” Abbott, who has touted grid readiness in recent months, said in a written statement. “I urge the Senate to swiftly confirm Peter’s appointment.”
On Monday, the Senate appeared to be moving quickly to confirm Abbott’s April 1 selection for the PUC, Will McAdams, president of Associated Builders and Contractors of Texas and a former legislative aide who helped write policy for regulated industries such as electricity.
McAdams was among the 129 nominees that the Senate Nominations Committee voted out, 8-0. His nomination heads now to the Senate floor.
All three of Abbott’s handpicked PUC commissioners who were in place before and during February’s calamitous winter storm have since quit or said they’re resigning, even as Sierra Club criticism of Abbott's demands intensified in the aftermath.
February’s polar vortex left in its wake physical and financial wreckage after a nonprofit grid operator answering to the PUC, amid calls for market reforms to avoid blackouts, shut off electricity to more than 4 million Texans, causing the deaths of at least 125 people, 13 of them in the Dallas-Fort Worth area.
Gov. Greg Abbott on Thursday named Will McAdams to the embattled Public Utility Commission of Texas. McAdams is a construction industry lobbyist with strong ties to the GOP-controlled Legislature. In Feb. 17 file photo, winter storm's snowfall andn large electrical transmission lines in South Arlington are pictured.
In a 45-minute confirmation hearing, McAdams, as lawmakers discussed ways to improve electricity reliability statewide, drew praise – and few tough questions.
McAdams, who previously worked for three GOP senators, testified that had he been on the commission in February, he would not have kept in place a controversial, $9,000-per-megawatt hour price cap on wholesale power for about 32 hours on Feb. 18-19.
“I don’t see myself making that decision,” he said.
McAdams, though, hedged slightly, saying he’s not privy to all information that the Electric Reliability Council of Texas, or ERCOT, and the PUC may have had at their disposal during the crisis.
The comments were notable because Lt. Gov. Dan Patrick and the Senate have fought with Abbott and the House over $16 billion in overcharges that, according to an independent market monitor, wrongly accrued near the end of the Feb. 15-19 outages.
Sen. Charles Schwertner, R-Georgetown, said the commission’s former chairwoman, DeAnn Walker, and Bill Magness, president of ERCOT, decided to hold the high cap in place because there “was still great concern about grid stability, even though there was significant reserves.”
He pressed McAdams to call that incorrect, which McAdams did.
“Given the fact pattern that I’m privy to, senator,” it wasn’t the right move, he said. “But again, there may be other facts out there. There probably are.”
McAdams acknowledged many homeowners and businesses were traumatized.
“The public’s confidence in the ability of the PUC to effectively regulate our electric markets has been badly damaged and shaken,” he said.
McAdams spoke favorably of renewable energy, calling wind and solar “absolutely valuable resources,” as the electricity sector faces profound change nationwide. To whatever extent those are not available, the PUC should “firm that up” with “dispatchable forms of generation,” such as gas, coal and nuclear, McAdams said.
He also called for lawmakers to consider providing electricity market bailout through “securitization,” or low-interest bond financing, to rural electric co-ops that were unable to pay the massive wholesale power bills they racked up during the February crisis.
“It would prevent those systems from having to front-load those costs onto their own members and smooth that out over a term of years,” while preventing an “uplift” of costs to other market participants who wisely hedged against soaring prices, McAdams said.
Noting that more than 400 bills have been filed to change ERCOT and how it’s governed, and as Texans prepare to vote on grid modernization funding this year, McAdams told the Senate panel, “It is clear to me that the Legislature wants meaningful changes to the status quo – to ensure that something positive comes out of this tragedy.”
Lake, who if confirmed by the Senate would replace Arthur D’Andrea as PUC chairman, grew up in Tyler. He attended prep school in New England and earned an undergraduate degree from the University of Chicago and a master of business administration degree from Stanford University.
He then worked for a commodities trading firm, a behavioral health company and as a business consultant before he became director of business development for Tyler-based Lake Ronel Oil Co. in 2014.
In late 2015, Abbott named Lake to the Texas Water Development Board and in February 2018 picked him to be the chairman of the three-member board that seeks to ensure water supplies for a fast-growing state.
Lake has steered the water board as it rolled out additional loans for water projects, approved by the Legislature and voters in 2013, and took the lead after Hurricane Harvey on flood control planning and infrastructure financing.
He’s posted exuberantly on Twitter as he toured agricultural water installations, lakes in West Texas and river authorities.
If confirmed, Lake and McAdams each would make $189,500 a year.
Related News
Europe must catch up with Asian countries on hydrogen fuel cells - report
Germany Hydrogen Fuel Cell Market gains momentum as policy, mobility, and R&D align; National Hydrogen Strategy, regulatory frameworks, and cost-of-ownership advances boost heavy transport, while Europe races Asia amid battery-electric competition and infrastructure scale-up.
Key Points
It is Germany and Europe's hydrogen fuel cell ecosystem across policy, costs, R&D, and mobility and freight deployments.
✅ Policy support via National Hydrogen Strategy and tax incentives
✅ TCO parity improves for heavy transport vs other low-emission tech
✅ R&D targets higher temps, compactness for road, rail, sea, air
In a new report examining the status of the German and European hydrogen fuel cell markets, the German government-backed National Platform Future of Mobility (NPM) says there is “a good chance that fuel cell technology can achieve a break-through in mobile applications,” even as the age of electric cars accelerates across markets.
However, Europe must catch up with Asian countries, it adds, even as a push for electricity shapes climate policy. For Germany and Europe to take on a leading role in fuel cell technologies, their industries need to be strengthened and sustainably developed, the report finds. In its paper, the NPM Working Group 4 – which aims to secure Germany as a place for mobility, battery cell production, recycling, training and qualification – states that the “chances of fuel cell technology achieving a break-through in the automotive industry – even in Europe – are better than ever,” echoing recent remarks from BMW's chief about hydrogen's appeal.
The development, expansion and use of the technology in various applications are now supported by “a significantly modified regulatory framework and new political ambitions, as stipulated in the National Hydrogen Strategy,” while updated forecasts show e-mobility driving electricity demand in Germany, the report stresses. In terms of cost of ownership, “hydrogen solutions can hold their own compared to other technologies” and there are “many promising developments in the transport sector, especially in heavy transport.”
If research and development efforts can help optimise installation space and weight as well as increase the operating temperature of fuel cells, hydrogen solutions can also become attractive for maritime, rail and air transport, even as other electrochemical approaches, such as flow battery cars, progress, the report notes. Tax incentives -- such as the Renewable Energy Sources Act (EEG) surcharge exemption for green hydrogen -- can contribute to the technology’s appeal, it adds.
Fuel cell drives are often seen as a way to decarbonise certain areas of transport, such as heavy trucks. However, producing the hydrogen in a sustainable way consumes a lot of renewable electricity that power companies must supply in other sectors, and experts say electricity vs hydrogen trade-offs favor battery-electric trucks because they are much cheaper to run than other low-emission technologies, including fuel cells.
Related News
How Bitcoin's vast energy use could burst its bubble
Bitcoin Energy Consumption drives debate on blockchain mining, proof-of-work, carbon footprint, and emissions, with CCAF estimates in terawatt hours highlighting electricity demand, fossil fuel reliance, and sustainability concerns for data centers and cryptocurrency networks.
Key Points
Electricity used by Bitcoin proof-of-work mining, often fossil-fueled, estimated by CCAF in terawatt hours.
✅ CCAF: 40-445 TWh, central estimate ~130 TWh
✅ ~66% of mining electricity sourced from fossil fuels
✅ Proof-of-work increases hash rate, energy, and emissions
The University of Cambridge Centre for Alternative Finance (CCAF) studies the burgeoning business of cryptocurrencies.
It calculates that Bitcoin's total energy consumption is somewhere between 40 and 445 annualised terawatt hours (TWh), with a central estimate of about 130 terawatt hours.
The UK's electricity consumption is a little over 300 TWh a year, while Argentina uses around the same amount of power as the CCAF's best guess for Bitcoin, as countries like New Zealand's electricity future are debated to balance demand.
And the electricity the Bitcoin miners use overwhelmingly comes from polluting sources, with the U.S. grid not 100% renewable underscoring broader energy mix challenges worldwide.
The CCAF team surveys the people who manage the Bitcoin network around the world on their energy use and found that about two-thirds of it is from fossil fuels, and some regions are weighing curbs like Russia's proposed mining ban amid electricity deficits.
Huge computing power - and therefore energy use - is built into the way the blockchain technology that underpins the cryptocurrency has been designed.
It relies on a vast decentralised network of computers.
These are the so-called Bitcoin "miners" who enable new Bitcoins to be created, but also independently verify and record every transaction made in the currency.
In fact, the Bitcoins are the reward miners get for maintaining this record accurately.
It works like a lottery that runs every 10 minutes, explains Gina Pieters, an economics professor at the University of Chicago and a research fellow with the CCAF team.
Data processing centres around the world, including hotspots such as Iceland's mining strain, race to compile and submit this record of transactions in a way that is acceptable to the system.
They also have to guess a random number.
The first to submit the record and the correct number wins the prize - this becomes the next block in the blockchain.
Estimates for bitcoin's electricity consumption
At the moment, they are rewarded with six-and-a-quarter Bitcoins, valued at about $50,000 each.
As soon as one lottery is over, a new number is generated, and the whole process starts again.
The higher the price, says Prof Pieters, the more miners want to get into the game, and utilities like BC Hydro suspending new crypto connections highlight grid pressures.
"They want to get that revenue," she tells me, "and that's what's going to encourage them to introduce more and more powerful machines in order to guess this random number, and therefore you will see an increase in energy consumption," she says.
And there is another factor that drives Bitcoin's increasing energy consumption.
The software ensures it always takes 10 minutes for the puzzle to be solved, so if the number of miners is increasing, the puzzle gets harder and the more computing power needs to be thrown at it.
Bitcoin is therefore actually designed to encourage increased computing effort.
The idea is that the more computers that compete to maintain the blockchain, the safer it becomes, because anyone who might want to try and undermine the currency must control and operate at least as much computing power as the rest of the miners put together.
What this means is that, as Bitcoin gets more valuable, the computing effort expended on creating and maintaining it - and therefore the energy consumed - inevitably increases.
We can track how much effort miners are making to create the currency.
They are currently reckoned to be making 160 quintillion calculations every second - that's 160,000,000,000,000,000,000, in case you were wondering.
And this vast computational effort is the cryptocurrency's Achilles heel, says Alex de Vries, the founder of the Digiconomist website and an expert on Bitcoin.
All the millions of trillions of calculations it takes to keep the system running aren't really doing any useful work.
"They're computations that serve no other purpose," says de Vries, "they're just immediately discarded again. Right now we're using a whole lot of energy to produce those calculations, but also the majority of that is sourced from fossil energy, and clean energy's 'dirty secret' complicates substitution."
The vast effort it requires also makes Bitcoin inherently difficult to scale, he argues.
"If Bitcoin were to be adopted as a global reserve currency," he speculates, "the Bitcoin price will probably be in the millions, and those miners will have more money than the entire [US] Federal budget to spend on electricity."
"We'd have to double our global energy production," he says with a laugh, even as some argue cheap abundant electricity is getting closer to reality today. "For Bitcoin."
He says it also limits the number of transactions the system can process to about five per second.
This doesn't make for a useful currency, he argues.
Rising price of bitcoin graphic
And that view is echoed by many eminent figures in finance and economics.
The two essential features of a successful currency are that it is an effective form of exchange and a stable store of value, says Ken Rogoff, a professor of economics at Harvard University in Cambridge, Massachusetts, and a former chief economist at the International Monetary Fund (IMF).
He says Bitcoin is neither.
"The fact is, it's not really used much in the legal economy now. Yes, one rich person sells it to another, but that's not a final use. And without that it really doesn't have a long-term future."
What he is saying is that Bitcoin exists almost exclusively as a vehicle for speculation.
So, I want to know: is the bubble about to burst?
"That's my guess," says Prof Rogoff and pauses.
"But I really couldn't tell you when."
Related News
UK leads G20 for share of electricity sourced from wind
UK Wind Power Leadership in 2020 highlights record renewable energy growth, G20-leading wind share, rapid coal phase-out, and rising solar integration, advancing decarbonization targets under the Paris Agreement and momentum ahead of COP26.
Key Points
The UK led the G20 in wind power share in 2020, displacing coal, expanding solar, and cutting power-sector emissions.
✅ G20-leading wind share; second for combined wind and solar
✅ Fastest coal decline among G20 from 2015 to 2020
✅ Emissions risk rising as post-pandemic demand returns
Nearly a quarter of the UK’s electricity came from wind turbines in 2020 – making the country the leader among the G20 for share of power sourced from the renewable energy, a new analysis finds.
The UK also moved away from coal power at a faster rate than any other G20 country from 2015 to 2020, according to the results.
And it ranked second in the G20, behind Germany, for the proportion of electricity sourced from both wind and solar in 2020, after first surpassing coal in 2016.
“It’s crazy how much wind power has grown in the UK and how much it has offset coal, and how it’s starting to eat at gas,” Dave Jones, Ember’s global lead analyst, told The Independent.
But it is important to bear in mind that “we’re only doing a great job by the standards of the rest of the world”, he added, noting that low-carbon generation stalled in 2019 in the UK.
Ember’s Global Electricity Review notes that the world’s power sector emissions were two per cent higher in 2020 than in 2015 – the year that countries agreed to slash their greenhouse gas pollution as part of the Paris Agreement.
Power generated from coal fell by a record amount from 2019 to 2020, the analysis finds. However, this decline was greatly facilitated by lockdowns introduced to stop the spread of Covid-19, as global electricity demand was temporarily stifled before rebounding, the analysts say.
Coal is the most polluting of the fossil fuels. The UK government hopes to convince all countries to stop building new coal-fired power stations at Cop26, a climate conference that is to be held in Glasgow later this year.
UN chief Antonio Guterres has also called for all countries to end their “deadly addiction to coal”.
At a summit held earlier this month, he described ending the use of coal in electricity generation as the “single most important step” to meeting the Paris Agreement’s goal of limiting global warming to well below 2C above pre-industrial levels by 2100.
“There is definitely a concern that, in the pandemic year of 2020, coal hasn’t fallen as fast as it needed to,” said Mr Jones, even as the UK set coal-free power records recently.
“There is concern that, once electricity demand returns, we won’t be seeing that decline in coal anymore.”
Related News
Canada must commit to 100 per cent clean electricity
Canada Green Investment Gap highlights lagging EV and clean energy funding as peers surge. With a green recovery budget pending, sustainable finance, green bonds, EV charging, hydrogen, and carbon capture are pivotal to decarbonization.
Key Points
Canada lags peers in EV and clean energy investment, urging faster budget and policy action to cut emissions.
✅ Per capita climate spend trails US and EU benchmarks
✅ EVs, hydrogen, charging need scaled funding now
✅ Strengthen sustainable finance, green bonds, disclosure
Canada is being outpaced on the international stage when it comes to green investments in electric vehicles and green energy solutions, environmental groups say.
The federal government has an opportunity to change course in about three weeks, when the Liberals table their first budget in over two years, the International Institute for Sustainable Development (IISD) argued in a new analysis endorsed by nine other climate action, ecology and conservation organizations.
“Canada’s international peers are ramping up commitments for green recovery, including significant investments from many European countries,” states the analysis, “Investing for Tomorrow, Today,” published March 29.
“To keep up with our global peers, sufficient investments and strengthened regulations, including EV sales regulations, must work in tandem to rapidly decarbonize all sectors of the Canadian economy.”
Deputy Prime Minister and Finance Minister Chrystia Freeland confirmed last week that the federal budget will be tabled April 19. The Liberals are expected to propose between $70 billion and $100 billion in fiscal stimulus to jolt the economy out of its pandemic doldrums.
The government teased a coming economic “green transformation” late last year when Freeland released the fall economic statement, promising to examine federal green bonds, border carbon adjustments and a sustainable finance market, with tweaks like tightening the climate-risk disclosure obligations of corporations.
The government has also proposed a wide range of green measures in its new climate plan released in December — which the think tank called the “most ambitious” in Canada’s history — including energy retrofit programs, boosting hydrogen and other alternative fuels, and rolling out carbon capture technology in a grid where 18% of electricity still came from fossil fuels in 2019.
But the possible “three-year stimulus package to jumpstart our recovery” mentioned in the fall economic statement came with the caveat that the COVID-19 virus would have to be “under control.” While vaccines are being administered, Canada is currently dealing with a rise of highly transmissible variants of the virus.
Freeland spoke with United States Vice-President Kamala Harris on March 25, highlighting potential Canada-U.S. collaboration on EVs alongside the “need to support entrepreneurs, small businesses, young people, low-wage and racialized workers, the care economy, and women” in the context of an economic recovery.
Biden is contemplating a climate recovery plan that could exceed US$2 trillion as Canada looks to capitalize on the U.S. auto pivot to EVs to spur domestic industry. Per capita, that is over 8 times what Canada has announced so far for climate-related spending in the wake of the pandemic, according to a new analysis from green groups.
U.S. President Joe Biden is contemplating a climate and clean energy recovery plan that could “exceed US$2 trillion,” White House officials told reporters this month. “Per capita, that is over eight times what Canada has announced so far for climate-related spending in the wake of the pandemic,” the IISD-led analysis stated.
Biden’s election platform commitment of $508 billion over 10 years in clean energy was also seen as “significantly higher per capita than Canada’s recent commitments.”
Since October 2020, Canada has announced $36 billion in new climate-focused funding, a 2035 EV mandate and other measures, the groups found. By comparison, they noted, a political agreement in Europe proposed that a minimum of 37 per cent of investments in each national recovery plan should support climate action. France and Germany have also committed tens of billions of dollars to support clean hydrogen.
As for electric vehicles (EVs), the United Kingdom has committed $4.9 billion, while Germany has put up $7.5 billion to expand EV adoption and charging infrastructure and sweeten incentive programs for prospective buyers, complementing Canada’s ambitious EV goals announced domestically. The U.K. has also committed $3.5 billion for bike lanes and other active transportation, the groups noted.
Canada announced $400 million over five years this month for a new network of bike lanes, paths, trails and bridges, the first federal fund dedicated to active transportation.
Related News
Prairie Provinces to lead Canada in renewable energy growth
Canada Renewable Power sees Prairie Provinces surge as Canada Energy Regulator projects rising wind, solar, and hydro capacity in Alberta, Saskatchewan, and Manitoba, replacing coal, expanding the grid, and lowering emissions through 2023.
Key Points
A CER outlook on Canada's grid: Prairie wind, solar, and hydro growth replacing coal and cutting emissions by 2023.
✅ Prairie wind, solar capacity surge by 2023
✅ Alberta, Saskatchewan shift from coal to renewables, gas
✅ Manitoba strengthens hydro leadership, low-carbon grid
Canada's Prairie Provinces will lead the country's growth in renewable energy capacity over the next three years, says a new report by the Canada Energy Regulator (CER).
The online report, titled Canada's Renewable Power, says decreased reliance on coal and substantial increases in wind and solar capacity will increase the amount of renewable energy added to the grid in Alberta and Saskatchewan. Meanwhile, Manitoba will strengthen its position as a prominent hydro producer in Canada. The pace of overall renewable energy growth is expected to slow at the national level between 2021 and 2023, in part due to lagging solar demand in some markets, but with strong growth in provinces with a large reliance on fossil fuel generation.
The report explores electricity generation in Canada and provides a short-term outlook for renewable electricity capacity in each province and territory to 2023. It also features a series of interactive visuals that allow for comparison between regions and highlights the diversity of electricity sources across Canada.
Electricity generation from renewable sources is expected to continue increasing as demand for electricity grows and the country continues its transition to a lower-carbon economy. Canada will see gradual declines in overall carbon emissions from electricity generation largely due to Saskatchewan, Alberta, Nova Scotia and New Brunswick replacing coal with renewables and natural gas. The pace of growth beyond 2023 in renewable power will depend on technological developments; consumer preferences; and government policies and programs.
Canada is a world leader in renewable power, generating almost two-thirds of its electricity from renewables with hydro as the dominant source, and the country ranks in the top 10 for hydropower jobs worldwide. Canada also has one of the world's lowest carbon intensities for electricity.
The CER produces neutral and fact-based energy analysis to inform the energy conversation in Canada. This report is part of a portfolio of publications on energy supply, demand and infrastructure that the CER publishes regularly as part of its ongoing market monitoring.
Report highlights
- Wind capacity in Saskatchewan is projected to triple and nearly double in Alberta between 2020 and 2023 as wind power becomes more competitive in the market. Significant solar capacity growth is also projected, with Alberta adding 1,200 MW by 2023, as Canada approaches a 5 GW solar milestone by that time.
- In Alberta, the share of renewables in the capacity mix is expected to increase from 16% in 2017 to 26% by 2023, with a renewable energy surge supporting thousands of jobs. Similarly, Saskatchewan's renewable share of capacity is expected to increase from 25% in 2018 to 33% in 2023.
- Renewable capacity growth slows most notably in Ontario, where policy changes have scaled back growth projections. Between 2010 and 2017, renewable capacity grew 6.8% per year. Between 2018 and 2023, growth in Ontario slows to 0.4% per year as capacity grows by 466 MW over this period.
- New large-scale hydro, wind, and solar projects will push the share of renewables in Canada's electricity mix from 67% of installed capacity in 2017 to 71% in 2023.
- Hydro is the dominant source of electricity in Canada accounting for 55% of total installed capacity and 59% of generation, though Alberta's limited hydro stands as a notable exception, with B.C., Manitoba, Quebec, Newfoundland and Labrador, and Yukon deriving more than 90% of their power from hydro.
- The jurisdictions with the highest percentage of non-hydro renewable electricity generation are PEI (100%), Nova Scotia (15.8%), and Ontario (10.5%).
- In 2010, 62.8% of Canada's total electricity generation (364 681 GW‧h) was from renewable sources. By 2018, 66.2% (425 722 GW‧h) was from renewable sources and projected to be 71.0% by 2023.
Related News
Canada is a solar power laggard, this expert says
Canada Distributed Energy faces disruption as solar, smart grids, microgrids, and storage scale utility-scale renewables, challenging centralized utilities and accelerating decarbonization, grid modernization, and distributed generation across provinces like Alberta.
Key Points
Canada Distributed Energy shifts from centralized grids to local solar, wind, and storage for reliable low-carbon power.
✅ Morgan Solar and Enbridge launch Alberta Solar One, 13.7 MW.
✅ Optical films boost panel efficiency, lowering cost per watt.
✅ Strong utilities slow adoption of microgrids and smart grids.
By Nick Waddell
Disruption is coming to electricity generation but Canada has become a laggard when it comes to not just adoption of alternative energy sources but in moving to a more distributed model of electricity generation. That’s according to Mike Andrade, CEO of Morgan Solar, whose new solar project in conjunction with Enbridge has just come online in Alberta, a province known as a powerhouse for both green and fossil energy in Canada.
“There’s a lot of inertia to Canada’s electrical system and I don’t think that bodes well,” said Andrade, who spoke on BNN Bloomberg on Thursday.
“Canada is one of the poorest places for uptake of solar, as NEB data on solar demand indicates,” Andrade said, “I believe a lot of it has to do with the fact that we have strong provincial utilities that have their mandates and their chosen technologies.”
Alberta Solar One, a 13.7 MW power facility near Lethbridge, Alberta, had its unveiling this week amid red-hot solar growth in Alberta that shows no sign of slowing. It’s a 36,500-panel farm constructed by Enbridge in a quick six-month turnaround as part of the power company’s pledge to become a carbon-free generator by 2050. Along with solar, Enbridge has made big investments in offshore and onshore wind farms in the United States, while also producing so-called green hydrogen at an Ontario plant.
Private company Morgan Solar considers the Alberta Solar One project as the first utility-scale validation of its technology, which uses optical films to redirect light onto photovoltaic cells to further power production.
“We use an advanced modelling system and a variety of tools to design very simple optical systems that can be easily inserted into a panel,” Andrade said. “They cost less and bring down the cost per watt. It captures light that would otherwise miss the cells and so you get more power per cell area than any other commercial technology at this point.”
Like renewables in general, solar energy has been thrust into the spotlight as governments worldwide aim to make good on their climate change and emissions pledges, with analyses showing zero-emissions electricity by 2035 is possible in Canada, and convert power generation from fossil fuels to alternative sources.
The market has paid attention, too, driving up values on renewable energy stocks across the board, including solar stocks, as provinces like Alberta explore selling renewable energy into broader markets. Last year, the Invesco Solar ETF, which tracks the MAC Global Solar Energy Index, soared 234 per cent, while Canadian companies with solar assets like Algonquin Power and Northland Power have been winners over the past few years.
Canadian cleantech companies involved in the solar power sector have also fared well, with names like UGE International (UGE International Stock Quote, Chart, News, Analyst. Financials TSXV:UGE), Aurora Solar and 5N Plus (5N Plus Stock Quote, Chart, News, Analysts, Financials TSX:VNP) having attracted investor attention of late.
Currently, part of the push in alternative energy involves the move from centralized to a more distributed picture of power generation, where solar panels, wind turbines and small modular nuclear reactors can operate close to or within sources of consumption like cities.
But Andrade says Canada has a lot of catching up to do on that front, especially as its current system seems devoted to maintaining the precedence of large, centralized power production — along with the utility companies that generate it.
“Canada is going to be left with this big, old fashioned hub and spoke model, and that’s increasingly going to be out-competed by a distributed grid, call them smart grids or micro grids,” Andrade said.
“That’s the future that solar is going to drive along with storage, and I personally don’t think Canada is prepared for it, not because we can’t do it but because regulatory and incumbency is holding us back from doing that,” he said.
“We pay our utilities, saying, ‘You invest capital and we’ll give you a fixed return on capital.’ Well, guess what? You’re going to get large, centralized capital projects which are going to get big central generation hub and spoke distribution,” Andrade said.
Ahead of the Canadian federal government’s tabling next week of its first budget in two years, many in the energy sector will be taking notes on the Liberal government’s investments in the so-called green recovery after the economic downturn, with renewable energy proponents hoping for further support, noting Alberta’s renewable energy surge could power thousands of jobs, to shift Canada’s resource sector away from fossil fuels.
By comparison, President Biden in the US recently unveiled his $2-billion infrastructure plan which put precedence on greening the country’s power grid, encouraging the adoption of electric vehicles and supporting renewable resource development, and Canadian studies suggest 2035 zero-emission power is practical and profitable as well across the national grid.
On disruption in power generation, Andrade said there are parallels to be drawn from information technology, which has historically made a point of discarded outdated models along the way.
“I was at IBM, and they had the mainframe business and that got blown up. I also worked with Nortel and Celestica and they got blown up —and it wasn’t due to having better central hub and spoke systems. They got beat up by this distributed system,” Andrade said.
“The same thing is going to happen here and the disruption is coming in electricity generation as well,” he said.
About The Author - Nick Waddell
Cantech Letter founder and editor Nick Waddell has lived in five Canadian provinces and is proud of his country's often overlooked contributions to the world of science and technology. Waddell takes a regular shift on the Canadian media circuit, making appearances on CTV, CBC and BNN, and contributing to publications such as Canadian Business and Business Insider.
Related News
The CIB and private sector partners to invest $1.7 billion in Lake Erie Connector
Lake Erie Connector Investment advances a 1,000 MW HVDC transmission link connecting Ontario to the PJM Interconnection, enhancing grid reliability, clean power trade, and GHG reductions through a public-private partnership led by CIB and ITC.
Key Points
A $1.7B public-private HVDC project linking Ontario and PJM to boost reliability, cut GHGs, and enable clean power trade.
✅ 1,000 MW, 117 km HVDC link between Ontario and PJM
✅ $655M CIB and $1.05B private financing, ITC to own-operate
✅ Cuts system costs, boosts reliability, reduces GHG emissions
The Canada Infrastructure Bank (CIB) and ITC Investment Holdings (ITC) have signed an agreement in principle to invest $1.7 billion in the Lake Erie Connector project.
Under the terms of the agreement, the CIB will invest up to $655 million or up to 40% of the project cost. ITC, a subsidiary of Fortis Inc., and private sector lenders will invest up to $1.05 billion, the balance of the project's capital cost.
The CIB and ITC Investment Holdings signed an agreement in principle to invest $1.7B in the Lake Erie Connector project.
The Lake Erie Connector is a proposed 117 kilometre underwater transmission line connecting Ontario with the PJM Interconnection, the largest electricity market in North America, and aligns with broader regional efforts such as the Maine transmission line to import Quebec hydro to strengthen cross-border interconnections.
The 1,000 megawatt, high-voltage direct current connection will help lower electricity costs for customers in Ontario and improve the reliability and security of Ontario's energy grid, complementing emerging solutions like battery storage across the province. The Lake Erie Connector will reduce greenhouse gas emissions and be a source of low-carbon electricity in the Ontario and U.S. electricity markets.
During construction, the Lake Erie Connector is expected to create 383 jobs per year and drive more than $300 million in economic activity, and complements major clean manufacturing investments like a $1.6 billion battery plant in the Niagara Region that supports the EV supply chain. Over its life, the project will provide 845 permanent jobs and economic benefits by boosting Ontario's GDP by $8.8 billion.
The project will also help Ontario to optimize its current infrastructure, avoid costs associated with existing production curtailments or shutdowns. It can leverage existing generation capacity and transmission lines to support electricity demand, alongside new resources such as the largest battery storage project planned for southwestern Ontario.
ITC continues its discussions with First Nations communities and is working towards meaningful participation in the near term and as the project moves forward to financial close.
The CIB anticipates financial close late in 2021, pending final project transmission agreements, with construction commencing soon after. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance.
ITC acquired the Lake Erie Connector project in August 2014 and it has received all necessary regulatory and permitting approvals, including a U.S. Presidential Permit and approval from the Canada Energy Regulator.
This is the CIB's first investment commitment in a transmission project and another example of the CIB's momentum to quickly implement its $10B Growth Plan, amid broader investments in green energy solutions in British Columbia that support clean growth.
Endorsements
This project will allow Ontario to export its clean, non-emitting power to one of the largest power markets in the world and, as a result, benefit Canadians economically while also significantly contributing to greenhouse gas emissions reductions in the PJM market. The project allows Ontario to better manage peak capacity and meet future reliability needs in a more sustainable way. This is a true win-win for both Canada and the U.S., both economically and environmentally.
Ehren Cory, CEO, Canada Infrastructure Bank
The Lake Erie Connector has tremendous potential to generate customer savings, help achieve shared carbon reduction goals, and increase electricity system reliability and flexibility. We look forward to working with the CIB, provincial and federal governments to support a more affordable, customer-focused system for Ontarians.
Jon Jipping, EVP & COO, ITC Investment Holdings Inc., a subsidiary of Canadian-based Fortis Inc.
We are encouraged by this recent announcement by the Canada Infrastructure Bank. Mississaugas of the Credit First Nation has an interest in projects within our historic treaty lands that have environmental benefits and that offer economic participation for our community.
Chief Stacey Laforme, Mississaugas of the Credit First Nation
While our evaluation of the project continues, we recognize this project can contribute to the economic resilience of our Shareholder, the Mississaugas of the Credit First Nation. Subject to the successful conclusion of our collaborative efforts with ITC, we look forward to our involvement in building the necessary infrastructure that enable Ontario's economic engine.
Leonard Rickard, CEO, Mississaugas of the Credit Business Corporation
The Lake Erie Connector demonstrates the advantages of public-private partnerships to develop critical infrastructure that delivers greater value to Ontarians. Connecting Ontario's electricity grid to the PJM electricity market will bring significant, tangible benefits to our province. This new connection will create high-quality jobs, improve system flexibility, and allow Ontario to export more excess electricity to promote cost-savings for Ontario's electricity consumers.
Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs
With the US pledging to achieve a carbon-free electrical grid by 2035, Canada has an opportunity to export clean power, helping to reduce emissions, maximizing clean power use and making electricity more affordable for Canadians. The Lake Erie Connector is a perfect example of that. The Canada Infrastructure Bank's investment will give Ontario direct access to North America's largest electricity market - 13 states and D.C. This is part of our infrastructure plan to create jobs across the country, tackle climate change, and increase Canada's competitiveness in the clean economy, alongside innovation programs like the Hydrogen Innovation Fund that foster clean technology.
Quick Facts
- The Lake Erie Connector is a 1,000 megawatt, 117 kilometre long underwater transmission line connecting Ontario and Pennsylvania.
- The PJM Interconnection is a regional transmission organization coordinating the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
- The project will help to reduce electricity system costs for customers in Ontario, and aligns with ongoing consultations on industrial electricity pricing and programs, while helping to support future capacity needs.
- The CIB is mandated to invest CAD $35 billion and attract private sector investment into new revenue-generating infrastructure projects that are in the public interest and support Canadian economic growth.
- The investment commitment is subject to final due diligence and approval by the CIB's Board.
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Bimbo Canada signs agreements to offset 100 per cent of its electricity consumption for Canadian operations
Bimbo Canada VPPAs secure renewable electricity from RES wind and solar projects in Alberta, totaling 170MW, via 15-year contracts to offset consumption, advance RE100 goals, and drive decarbonization across bakeries, depots, and distribution centers.
Key Points
Virtual power purchase agreements sourcing wind and solar to offset Bimbo Canadas electricity and support RE100.
✅ 15-year RES contracts for Alberta wind and solar capacity
✅ Offsets electricity for bakeries, depots, and distribution centers
✅ Advances Grupo Bimbo RE100 target for 100% renewable power
Canada's oldest and largest bakery, Bimbo Canada, has signed two virtual power purchase agreements (VPPAs) with Renewable Energy Systems (RES) to procure renewable electricity, similar to federal green electricity contracts advancing in Alberta, that will offset 100 per cent of the company's electricity consumption in Canada. The projects are expected to be fully operational by December, 2022.
Canada is the second market, alongside the United States, to enter into VPPAs, where companies like Amazon clean energy projects are expanding rapidly. These agreements, together with additional sustainability initiatives conducted around the world by the parent company Grupo Bimbo, will help the company offset 90 per cent of its global electricity consumption.
"Bimbo Canada is committed to nourishing a better world through productive sustainability practices," said Joe McCarthy, president of Bimbo Canada. "These agreements are the next big step in reducing our environmental footprint, as peers such as Arvato's first solar plant signal industry momentum, and becoming leaders in responsible stewardship of the environment."
The 15-year agreements with RES will support the commercial development of two renewable energy projects in southern Alberta, consisting of wind and solar projects, similar to RBC's solar PPA announced in the region, totaling 170MW of installed capacity. Under these two agreements, Bimbo Canada will procure the benefit of approximately 50MW of renewable electricity to offset electricity consumption for its 16 bakeries, 14 distribution centres and 191 depots. Commercial development for the wind and solar farms will be finalized later this year by RES Canada and the projects are expected to be fully operational by the end of next year.
"RES is proud that its Alberta wind and solar projects, amid growth such as a $200M Alberta wind farm led by a Buffett-linked firm, are helping Bimbo Canada meet its sustainability initiatives," said Peter Clibbon, RES Senior VP of Development. "It's a win-win situation with our projects delivering competitive wind and solar electricity to Bimbo Canada, and while providing our host communities with long-term tax and landowner income."
In 2018, Grupo Bimbo joined RE100, a global initiative led by The Climate Group and in partnership with Carbon Disclosure Project (CDP) and committed to operating with 100 per cent renewable electricity by 2025. As a leading supplier of fresh-baked goods and snacks for Canadian families, these agreements support the company's targets and builds upon many successful past sustainability initiatives, as market activity by Canadian Solar project sales continues nationwide.
"The renewable electricity initiatives in our operations respond to Grupo Bimbo's deep commitment that we have had for many decades globally with the planet and with present and future generations," said Daniel Servitje, global CEO of Grupo Bimbo. "With this announcement, we have achieved another important milestone for the company on our journey towards becoming 100 per cent renewable electricity by 2025."
Last year, Bimbo Canada reduced product waste and exceeded its product waste reduction target by 18 per cent, which saved four million units of products from landfills. The company also eliminated 174 metric tonnes of plastic per year (equal to 43 adult elephants) through several packaging optimization initiatives.
Earlier this year, Bimbo Canada signed the Canada Plastics Pact (CPP) and, amid a broader push for clean energy exemplified by Edmonton rooftop solar installations, earned its first ENERGY STAR certification for its Hamilton, Ontario bakery. The company will continue to work towards other initiatives that fulfill its commitment to be a sustainable, highly productive and deeply humane company.
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This Floating Hotel Will Generate Electricity By Rotating All Day
Floating Rotating Eco Hotel harnesses renewable energy via VAWTAU, recycles rainwater for greywater, and follows zero-waste principles. This mobile, off-grid, Qatar-based resort generates electricity by slow 360-degree rotation while offering luxury amenities.
Key Points
A mobile, off-grid hotel that rotates to generate power, uses VAWTAU, recycles greywater, and targets zero-waste.
✅ Rotates 360 deg in 24 hours to produce electricity
✅ VAWTAU system: vertical-axis turbine and sun umbrella
✅ Rain capture and greywater recycling minimize waste
A new eco-friendly, floating hotel plans to generate its own electricity by rotating while guests relax on board, echoing developments like the solar Marriott hotel in sustainable hospitality.
Led by Hayri Atak Architectural Design Studio (HAADS), the structure will be completely mobile, meaning it can float from place to place, never sitting in a permanent position. Building began in March 2020 and the architects aim for it to be up and running by 2025.
It will be based in Qatar, but has the potential to be located in different areas due to its mobility, and it sits within a region advancing projects such as solar hydrogen production that signal a broader clean-energy shift.
The design includes minimum energy loss and a zero waste principle at its core, aligning with progress in wave energy research that aims to power a clean future. As it will rotate around all day long, this will generate electrical energy to power the whole hotel.
But guests won’t feel too dizzy, as it takes 24 hours for the hotel to spin 360 degrees.
The floating hotel will stay within areas with continuous currents, to ensure that it is always rotating, drawing on ideas from ocean and river power systems that exploit natural flows. This type of green energy production is called ‘vawtau’ (vertical axis wind turbine and umbrella) which works like a wind turbine on the vertical axis, while alternative approaches like kite-based wind energy target stronger, high-altitude currents as well, and functions as a sun umbrella on the coastal band.
Beyond marine-current concepts such as underwater kites, the structure will also make use of rainwater to create power. A cover on the top of the hotel will collect rain to be used for greywater recycling. This is when wastewater is plumbed straight back into toilets, washing machines or outside taps to maximise efficiency.
The whole surface area is around 35,000 m², comparable in scale to emerging floating solar plants that demonstrate modular, water-based infrastructure, and there are a total of 152 rooms. It will have three different entrances so that there is access to the land at any time of the day, thanks to the 140-degree pier that surrounds it.
There will also be indoor and outdoor swimming pools, a sauna, spa, gym, mini golf course and other activity areas.
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Ontario Energy Board prohibiting electricity shutoffs during latest stay-at-home order
OEB Disconnection Ban shields Ontario residential customers under the stay-at-home order, pausing electricity distributor shutoffs for non-payment and linking COVID-19 Energy Assistance Program credits for small businesses, charities, and overdue utility bills.
Key Points
A pause on electricity shutoff notices during Ontario's stay-at-home order, with COVID-19 bill credits for customers.
✅ Distributors cannot issue residential disconnection notices.
✅ Applies through the stay-at-home order timeline.
✅ CEAP credits: $750 residential; $1,500 small biz and charities.
With Ontario now into the third province-wide lockdown, the Ontario Energy Board (OEB) has promised residents won't have to worry about their power being shut off.
On April 8, the Province issued the third stay-at-home order in the last 13 months which is scheduled to last for 28 days until at least May 6, as electricity rates and policies continue to shift.
On April 30, the annual winter disconnection ban is set to expire, meaning electricity distributors like Hydro One would normally be permitted to issue disconnection notices for non-payment as early as 14 days before the end of the ban.
However, the OEB has announced changes for electricity consumers that prohibit electricity distributors from issuing disconnection notices to residential customers for the entirety of the stay-at-home order.
Additionally, the COVID-19 Energy Assistance Program is available for residential, small business, and registered charity customers who have overdue amounts on their electricity or gas bills as a result of the pandemic, complementing support for electric bills introduced during COVID-19, and the fixed COVID-19 hydro rate that helped stabilize costs.
Those who meet these criteria are eligible for credits up to a maximum of $750 for residential customers and $1,500 for small businesses and charities, alongside earlier moves to set an off-peak price to ease costs.
