Electricity use actually increased during 2018 Earth Hour, BC Hydro


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Earth Hour BC highlights BC Hydro data on electricity use, energy savings, and participation in the Lower Mainland and Vancouver Island amid climate change and hydroelectric power dynamics.

 

Key Points

BC observance tracking BC Hydro electricity use and conservation during Earth Hour, amid hydroelectric power dominance.

✅ BC Hydro reports rising electricity use during Earth Hour 2018

✅ Savings fell from 2% in 2008 to near zero province-wide

✅ Hydroelectric grid yields low GHG emissions in BC

 

For the first time since it began tracking electricity use in the province during Earth Hour, BC Hydro said customers used more power during the 60-minute period when lights are expected to dim, mirroring all-time high electricity demand seen recently.

The World Wildlife Fund launched Earth Hour in Sydney, Australia in 2007. Residents and businesses there turned off lights and non-essential power as a symbol to mark the importance of combating climate change.

The event was adopted in B.C. the next year and, as part of that, BC Hydro began tracking the megawatt hours saved.

#google#

In 2008, residents and businesses achieved a two per cent savings in electricity use. But since then, BC Hydro says the savings have plummeted.

The event was adopted in B.C. the next year and, as part of that, BC Hydro began tracking the megawatt hours saved.

In 2008, residents and businesses achieved a two per cent savings in electricity use. But since then, BC Hydro says the savings have plummeted, as record-breaking demand in 2021 and beyond changed consumption patterns.

 

Lights on

For Earth Hour this year, which took place 8:30-9:30 p.m. on March 24, BC Hydro says electricity use in the Lower Mainland increased by 0.5 per cent, even as it activated a winter payment plan to help customers manage bills. On Vancouver Island it increased 0.6 per cent.

In the province's southern Interior and northern Interior, power use remained the same during the event.

On Friday, the utility released a report called: "lights out". Why Earth Hour is dimming in BC. which explores the decline of energy savings related to Earth Hour in the province.

The WWF says the way in which hydro companies track electricity savings during Earth Hour is not an accurate measure of participation, and tracking of emerging loads like crypto mining electricity use remains opaque, and noted that more countries than ever are turning off lights for the event.

For 2018, the WWF shifted the focus of Earth Hour to the loss of wildlife across the globe.

BC Hydro says in its report that the symbolism of Earth Hour is still important to British Columbians, but almost all power generation in B.C. is hydroelectric, though recent drought conditions have required operational adjustments, and only accounts for one per cent of greenhouse gas emissions.

 

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Daimler Details Gigantic Scope of Its Electrification Plan

Daimler Electric Strategy drives EV adoption with global battery factories, Mercedes-Benz electrified models, battery cells procurement, and major investments spanning vans, buses, trucks, and production capacity across Europe, Asia, and the USA.

 

Key Points

Daimler Electric Strategy is a multi-billion EV roadmap for batteries, factories, and 130 electrified Mercedes models.

✅ Eight battery factories across three continents

✅ EUR 10B for EV lineup; EUR 20B for battery cells

✅ 130 electrified variants plus vans, buses, trucks

 

Throughout 2018, we all witnessed the unprecedented volume of promises for a better future made by the giants of the auto industry. All say they've committed billions so that, within a decade, combustion engines will be on their way out.

The most active of all companies when talking about promises is Volkswagen, which, amid German plant closures, time and time again has said it will do this or that and completely change the meaning of car in the coming years. But there are other planning the same thing, possibly with even vaster resources.

Planning to end the year on a high note, Daimler detailed its plan for the electric future once again on Tuesday, this time making no secret of its gigantic size and scope.

As announced before, Daimler plans to build electric cars, but also manufacture electric batteries for its own and others’ use, and has launched a US energy storage company to support this strategy. These batteries will eventually be produced by Daimler in eight factories on three continents.

Batteries are already rolling off the lines in Kamenz, and a second facility will begin doing so next year. Two more factories will be built in Stuttgart-Untertürkheim, one at the company’s Sindelfingen site, and one each at the sites in Beijing (China), Bangkok (Thailand) and Tuscaloosa (USA).

In all, one billion EUR will be invested in the expansion of the global battery production network, but that is nothing compared to the 10 billion to be poured into the expansion of the Mercedes-Benz car fleet.

On top of that, 20 billion EUR will go towards the purchase of battery cells from producers all around the world, echoing other automakers' battery sourcing strategies worldwide over the next 12 years.

“After investing billions of euros in the development of the electric fleet and the expansion of our global battery network, we are now taking the next step,” said in a statement Dieter Zetsche, Daimler chairman of the board.

“With the purchase of battery cells for more than 20 billion euros, we are systematically pushing forward with the transformation into the electric future of our company.”

By 2022, the carmaker plans to launch 130 electrified variants of its cars, as cheaper, more powerful batteries become available, adding to them electric vans, buses and trucks. That pretty much means all the models and variants sold by Daimler globally will be at least partially powered by electricity.

 

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Utilities see benefits in energy storage, even without mandates

Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

 

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

 

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

 

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Longer, more frequent outages afflict the U.S. power grid as states fail to prepare for climate change

Power Grid Climate Resilience demands storm hardening, underground power lines, microgrids, batteries, and renewable energy as regulators and utilities confront climate change, sea level rise, and extreme weather to reduce outages and protect vulnerable communities.

 

Key Points

It is the grid capacity to resist and recover from climate hazards using buried lines, microgrids, and batteries.

✅ Underground lines reduce wind outages and wildfire ignition risk.

✅ Microgrids with solar and batteries sustain critical services.

✅ Regulators balance cost, resilience, equity, and reliability.

 

Every time a storm lashes the Carolina coast, the power lines on Tonye Gray’s street go down, cutting her lights and air conditioning. After Hurricane Florence in 2018, Gray went three days with no way to refrigerate medicine for her multiple sclerosis or pump the floodwater out of her basement.

What you need to know about the U.N. climate summit — and why it matters
“Florence was hell,” said Gray, 61, a marketing account manager and Wilmington native who finds herself increasingly frustrated by the city’s vulnerability.

“We’ve had storms long enough in Wilmington and this particular area that all power lines should have been underground by now. We know we’re going to get hit.”

Across the nation, severe weather fueled by climate change is pushing aging electrical systems past their limits, often with deadly results. Last year, amid increasing nationwide blackouts, the average American home endured more than eight hours without power, according to the U.S. Energy Information Administration — more than double the outage time five years ago.

This year alone, a wave of abnormally severe winter storms caused a disastrous power failure in Texas, leaving millions of homes in the dark, sometimes for days, and at least 200 dead. Power outages caused by Hurricane Ida contributed to at least 14 deaths in Louisiana, as some of the poorest parts of the state suffered through weeks of 90-degree heat without air conditioning.

As storms grow fiercer and more frequent, environmental groups are pushing states to completely reimagine the electrical grid, incorporating more grid-scale batteries, renewable energy sources and localized systems known as “microgrids,” which they say could reduce the incidence of wide-scale outages. Utility companies have proposed their own storm-proofing measures, including burying power lines underground.

But state regulators largely have rejected these ideas, citing pressure to keep energy rates affordable. Of $15.7 billion in grid improvements under consideration last year, regulators approved only $3.4 billion, according to a national survey by the NC Clean Energy Technology Center — about one-fifth, highlighting persistent vulnerabilities in the grid nationwide.

After a weather disaster, “everybody’s standing around saying, ‘Why didn’t you spend more to keep the lights on?’ ” Ted Thomas, chairman of the Arkansas Public Service Commission, said in an interview with The Washington Post. “But when you try to spend more when the system is working, it’s a tough sell.”

A major impediment is the failure by state regulators and the utility industry to consider the consequences of a more volatile climate — and to come up with better tools to prepare for it. For example, a Berkeley Lab study last year of outages caused by major weather events in six states found that neither state officials nor utility executives attempted to calculate the social and economic costs of longer and more frequent outages, such as food spoilage, business closures, supply chain disruptions and medical problems.

“There is no question that climatic changes are happening that directly affect the operation of the power grid,” said Justin Gundlach, a senior attorney at the Institute for Policy Integrity, a think tank at New York University Law School. “What you still haven’t seen … is a [state] commission saying: 'Isn’t climate the through line in all of this? Let’s examine it in an open-ended way. Let’s figure out where the information takes us and make some decisions.’ ”

In interviews, several state commissioners acknowledged that failure.

“Our electric grid was not built to handle the storms that are coming this next century,” said Tremaine L. Phillips, a commissioner on the Michigan Public Service Commission, which in August held an emergency meeting to discuss the problem of power outages. “We need to come up with a broader set of metrics in order to better understand the success of future improvements.”

Five disasters in four years
The need is especially urgent in North Carolina, where experts warn Atlantic grids and coastlines need a rethink as the state has declared a federal disaster from a hurricane or tropical storm five times in the past four years. Among them was Hurricane Florence, which brought torrential rain, catastrophic flooding and the state’s worst outage in over a decade in September 2018.

More than 1 million residents were left disconnected from refrigerators, air conditioners, ventilators and other essential machines, some for up to two weeks. Elderly residents dependent on oxygen were evacuated from nursing homes. Relief teams flew medical supplies to hospitals cut off by flooded roads. Desperate people facing closed stores and rotting food looted a Wilmington Family Dollar.

“I have PTSD from Hurricane Florence, not because of the actual storm but the aftermath,” said Evelyn Bryant, a community organizer who took part in the Wilmington response.

The storm reignited debate over a $13 billion proposal by Duke Energy, one of the largest power companies in the nation, to reinforce the state’s power grid. A few months earlier, the state had rejected Duke’s request for full repayment of those costs, determining that protecting the grid against weather is a normal part of doing business and not eligible for the type of reimbursement the company had sought.

After Florence, Duke offered a smaller, $2.5 billion plan, along with the argument that severe weather events are one of seven “megatrends” (including cyberthreats and population growth) that require greater investment, according to a PowerPoint presentation included in testimony to the state. The company owns the two largest utilities in North Carolina, Duke Energy Carolinas and Duke Energy Progress.

Vote Solar, a nonprofit climate advocacy group, objected to Duke’s plan, saying the utility had failed to study the risks of climate impacts. Duke’s flood maps, for example, had not been updated to reflect the latest projections for sea level rise, they said. In testimony, Vote Solar claimed Duke was using environmental trends to justify investments “it had already decided to pursue.”

The United States is one of the few countries where regulated utilities are usually guaranteed a rate of return on capital investments, even as studies show the U.S. experiences more blackouts than much of the developed world. That business model incentivizes spending regardless of how well it solves problems for customers and inspires skepticism. Ric O’Connell, executive director of GridLab, a nonprofit group that assists state and regional policymakers on electrical grid issues, said utilities in many states “are waving their hands and saying hurricanes” to justify spending that would do little to improve climate resilience.

In North Carolina, hurricanes convinced Republicans that climate change is real

Duke Energy spokesman Jeff Brooks acknowledged that the company had not conducted a climate risk study but pointed out that this type of analysis is still relatively new for the industry. He said Duke’s grid improvement plan “inherently was designed to think about future needs,” including reinforced substations with walls that rise several feet above the previous high watermark for flooding, and partly relied on federal flood maps to determine which stations are at most risk.

Brooks said Duke is not using weather events to justify routine projects, noting that the company had spent more than a year meeting with community stakeholders and using their feedback to make significant changes to its grid improvement plan.

This year, the North Carolina Utilities Commission finally approved a set of grid improvements that will cost customers $1.2 billion. But the commission reserved the right to deny Duke reimbursement of those costs if it cannot prove they are prudent and reasonable. The commission’s general counsel, Sam Watson, declined to discuss the decision, saying the commission can comment on specific cases only in public orders.

The utility is now burying power lines in “several neighborhoods across the state” that are most vulnerable to wide-scale outages, Brooks said. It is also fitting aboveground power lines with “self-healing” technology, a network of sensors that diverts electricity away from equipment failures to minimize the number of customers affected by an outage.

As part of a settlement with Vote Solar, Duke Energy last year agreed to work with state officials and local leaders to further evaluate the potential impacts of climate change, a process that Brooks said is expected to take two to three years.

High costs create hurdles
The debate in North Carolina is being echoed in states across the nation, where burying power lines has emerged as one of the most common proposals for insulating the grid from high winds, fires and flooding. But opponents have balked at the cost, which can run in the millions of dollars per mile.

In California, for example, Pacific Gas & Electric wants to bury 10,000 miles of power lines, both to make the grid more resilient and to reduce the risk of sparking wildfires. Its power equipment has contributed to multiple deadly wildfires in the past decade, including the 2018 Camp Fire that killed at least 85 people.

PG&E’s proposal has drawn scorn from critics, including San Jose Mayor Sam Liccardo, who say it would be too slow and expensive. But Patricia Poppe, the company’s CEO, told reporters that doing nothing would cost California even more in lost lives and property while struggling to keep the lights on during wildfires. The plan has yet to be submitted to the state, but Terrie Prosper, a spokeswoman for the California Public Utilities Commission, said the commission has supported underground lines as a wildfire mitigation strategy.

Another oft-floated solution is microgrids, small electrical systems that provide power to a single neighborhood, university or medical center. Most of the time, they are connected to a larger utility system. But in the event of an outage, microgrids can operate on their own, with the aid of solar energy stored in batteries.

In Florida, regulators recently approved a four-year microgrid pilot project, but the technology remains expensive and unproven. In Maryland, regulators in 2016 rejected a plan to spend about $16 million for two microgrids in Baltimore, in part because the local utility made no attempt to quantify “the tangible benefits to its customer base.”

Amid shut-off woes, a beacon of energy

In Texas, where officials have largely abandoned state regulation in favor of the free market, the results have been no more encouraging. Without requirements, as exist elsewhere, for building extra capacity for times of high demand or stress, the state was ill-equipped to handle an abnormal deep freeze in February that knocked out power to 4 million customers for days.

Since then, Berkshire Hathaway Energy and Starwood Energy Group each proposed spending $8 billion to build new power plants to provide backup capacity, with guaranteed returns on the investment of 9 percent, but the Texas legislature has not acted on either plan.

New York is one of the few states where regulators have assessed the risks of climate change and pushed utilities to invest in solutions. After 800,000 New Yorkers lost power for 10 days in 2012 in the wake of Hurricane Sandy, state regulators ordered utility giant Con Edison to evaluate the state’s vulnerability to weather events.

The resulting report, which estimated climate risks could cost the company as much as $5.2 billion by 2050, gave ConEd data to inform its investments in storm hardening measures, including new storm walls and submersible equipment in areas at risk of flooding.

Meanwhile, the New York Public Service Commission has aggressively enforced requirements that utility companies keep the lights on during big storms, fining utility providers nearly $190 million for violations including inadequate staffing during Tropical Storm Isaias in 2020.

“At the end of the day, we do not want New Yorkers to be at the mercy of outdated infrastructure,” said Rory M. Christian, who last month was appointed chair of the New York commission.

The price of inaction
In North Carolina, as Duke Energy slowly works to harden the grid, some are pursuing other means of fostering climate-resilient communities.

Beth Schrader, the recovery and resilience director for New Hanover County, which includes Wilmington, said some of the people who went the longest without power after Florence had no vehicles, no access to nearby grocery stores and no means of getting to relief centers set up around the city.

For example, Quanesha Mullins, a 37-year-old mother of three, went eight days without power in her housing project on Wilmington’s east side. Her family got by on food from the Red Cross and walked a mile to charge their phones at McDonald’s. With no air conditioning, they slept with the windows open in a neighborhood with a history of violent crime.

Schrader is working with researchers at the University of North Carolina in Charlotte to estimate the cost of helping people like Mullins. The researchers estimate that it would have cost about $572,000 to provide shelter, meals and emergency food stamp benefits to 100 families for two weeks, said Robert Cox, an engineering professor who researches power systems at UNC-Charlotte.

Such calculations could help spur local governments to do more to help vulnerable communities, for example by providing “resilience outposts” with backup power generators, heating or cooling rooms, Internet access and other resources, Schrader said. But they also are intended to show the costs of failing to shore up the grid.

“The regulators need to be moved along,” Cox said.

In the meantime, Tonye Gray finds herself worrying about what happens when the next storm hits. While Duke Energy says it is burying power lines in the most outage-prone areas, she has yet to see its yellow-vested crews turn up in her neighborhood.

“We feel,” she said, “that we’re at the end of the line.”

 

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TransAlta brings online 119 MW of wind power in US

TransAlta Renewables US wind farms achieved commercial operation, adding 119 MW of wind energy capacity in Pennsylvania and New Hampshire, backed by PPAs with Microsoft, Partners Healthcare, and NHEC, and supported by tax equity financing.

 

Key Points

Two US wind projects totaling 119 MW, now online under PPAs and supported by tax equity financing.

✅ 119 MW online in Pennsylvania and New Hampshire

✅ PPAs with Microsoft, Partners Healthcare, and NHEC

✅ About USD 126 million raised via tax equity

 

TransAlta Renewables Inc says two US wind farms, with a total capacity of 119 MW and operated by its parent TransAlta Corp, became operational in December, amid broader build-outs such as Enel's 450-MW U.S. project coming online and, in Canada, Acciona's 280-MW Alberta wind farm advancing as well.

The 90-MW Big Level wind park in Pennsylvania started commercial operation on December 19. It sells power to technology giant Microsoft Corporation under a 15-year contract, reflecting big-tech procurement alongside Amazon's clean energy projects in multiple markets.

The 29-MW Antrim wind facility in New Hampshire is operational since December 24. It is selling power under 20-year contracts with Boston-based non-profit hospital and physicians network Partners Healthcare and New Hampshire Electric Co-op, mirroring East Coast activity at Amazon Wind Farm US East now fully operational.

The Canadian renewable power producer, which has economic interest in the two wind parks, said that upon their reaching commercial operations, it raised about USD 126 million (EUR 113m) of tax equity to partially fund the projects, as mega-deployments like Invenergy and GE's record North American project and capital plans such as a $200 million Alberta build by a Buffett-linked company underscore financing momentum.

"We continue to pursue additional growth opportunities, including potential drop-down transactions with TransAlta Corp," TransAlta Renewables president John Kousinioris commented.

The comment comes as TransAlta scrapped an Alberta wind project amid Alberta policy shifts.

 

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With New Distributed Energy Rebate, Illinois Could Challenge New York in Utility Innovation

Illinois NextGrid redefines utility, customer, and provider roles with grid modernization, DER valuation, upfront rebates, net metering reform, and non-wires alternatives, leveraging rooftop solar, batteries, and performance signals to enhance reliability and efficiency.

 

Key Points

Illinois NextGrid is an ICC roadmap to value DER and modernize the grid with rebates and non-wires solutions.

✅ Upfront Value-of-DER rebates reward location, time, and performance.

✅ Locational DER reduce peak demand and defer wires and substations.

✅ Encourages non-wires alternatives and data-driven utility planning.

 

How does the electric utility fit in to a rapidly-evolving energy system? That’s what the Illinois Commerce Commission is trying to determine with its new effort, "NextGrid". Together, we’re rethinking the roles of the utility, the customer, and energy solution providers in a 21st-century digital grid landscape.

In some ways, NextGrid will follow in the footsteps of New York’s innovative Reforming the Energy Vision process, a multi-year effort to re-examine how electric utilities and customers interact. A new approach is essential to accelerating the adoption of clean energy technologies and building a smarter electricity infrastructure in the state.

Like REV, NextGrid is gaining national attention for stakeholder-driven processes to reveal new ways to value distributed energy resources (DER), like rooftop solar and batteries. New York and Illinois’ efforts also seek alternatives, such as virtual power plants, to simply building more and more wires, poles, and power plants to meet the energy needs of tomorrow.

Yet, Illinois is may go a few steps beyond New York, creating a comprehensive framework for utilities to measure how DER are making the grid smarter and more efficient. Here is what we know will happen so far.

On Wednesday, April 5, at the second annual Grid Modernization Forum in Chicago, I’ll be discussing why these provisions could change the future of our energy system, including insights on grid modernization affordability for stakeholders.

 

Value of distributed energy

The Illinois Commerce Commission’s NextGrid plans grew out of the recently-passed future energy jobs act, a landmark piece of climate and energy policy that was widely heralded as a bipartisan oddity in the age of Trump. The Future Energy Jobs Act will provide significant new investments in renewables and energy efficiency over the next 13 years, redefine the role and value of rooftop solar and batteries on the grid, and lead to significant greenhouse gas emission reductions.

NextGrid will likely start laying the groundwork for valuing distributed energy resources (DER) as envisioned by the Future Energy Jobs Act, which introduces the concept of a new rebate. Illinois currently has a net metering policy, which lets people with solar panels sell their unused solar energy back to the grid to offset their electric bill. Yet the net metering policy had an arbitrary “cap,” or a certain level after which homes and businesses adding solar panels would no longer be able to benefit from net metering.

Although Illinois is still a few years away from meeting that previous “cap,” when it does hit that level, the new policy will ensure additional DER will still be rewarded. Under the new plan, the Value-of-DER rebate will replace net metering on the distribution portion of a customer’s bill (the charge for delivering electricity from the local substation to your house) with an upfront payment, which credits the customer for the value their solar provides to the local grid over the system’s life. Net metering for the energy supply portion of the bill would remain – i.e. homes and businesses would still be able to offset a significant portion of their electric bills by selling excess energy.

What is unique about Illinois’ approach is that the rebate is an upfront payment, rather than on ongoing tariff or reduced net metering compensation, for example. By allowing customers to get paid for the value solar provides to the system at the time it is installed, in the same way new wires, poles, and transformers would, this upfront payment positions DER investments as equally or more beneficial to customers and the electric grid. This is a huge step not only for regulators, but for utilities as well, as they begin to see distributed energy as an asset to the system.

This is a huge step for utilities, as they begin to see distributed energy as an asset to the system.

The rebate would also factor-in the variables of location, time, and performance of DER in the rebate formula, allowing for a more precise calculation of the value to the grid. Peak electricity demand can stress the local grid, causing wear and tear and failure of the equipment that serve our homes and businesses. Power from DER during peak times and in certain areas can alleviate those stresses, therefore providing a greater value than during times of average demand.

In addition, factoring-in the value of performance will take into account the other functions of distributed energy that help keep the lights on. For example, batteries and advanced inverters can provide support for helping avoid voltage fluctuations that can cause outages and other costs to customers.

 

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Quebec Halts Crypto Mining Electricity Requests

Hydro-Quebec Crypto Mining Pause signals a temporary halt as blockchain power requests surge; energy regulator review will weigh electricity demand, winter peak constraints, tariffs, investments, and local jobs to optimize grid stability and revenues.

 

Key Points

A provincial halt on new miner power requests as Hydro-Quebec sets rules to safeguard demand, winter peaks, and rates.

✅ Temporary halt on new electricity sales to crypto miners

✅ Regulator to rank projects by jobs, investment, and revenue

✅ Winter peak demand and tariffs central to new framework

 

Major Canadian electricity provider Hydro-Québec will temporarily stop processing requests from cryptocurrency miners in order for the company to fulfil its obligations to supply energy to the entire province, while its global ambitions adjust to changing demand, according to a press release published June 7.

Hydro-Québec is experiencing “unprecedented” demand from blockchain companies, which reportedly exceeds the electric utility’s short and medium-term capacity. In this regard, the Quebec provincial government has ordered Hydro-Québec to halt electric power sales to cryptocurrency miners, and, following the New Hampshire rejection of Northern Pass announced a new framework for this category of electricity consumers.

In the coming days, Hydro-Québec will reportedly file an application to local energy regulator Régie de l'énergie, proposing a selection process for blockchain industry projects so as “not to miss the opportunities offered by this industry.” Regulators will reportedly target companies which can offer the province the most profitable economic advantages, including investments and local job creation.

#google#

Régie de l'énergie is instructed to consider “the need for a reserved block of energy for this category of consumers, the possibility of maximizing Hydro-Québec's revenues, and issues related to the winter peak period” as well as interprovincial arrangements like the Ontario-Québec electricity deal under discussion. Éric Filion, President of Hydro-Québec Distribution, said:

"The blockchain industry is a promising avenue for Hydro-Québec. Guidelines are nevertheless required to ensure that the development of this industry maximizes spinoffs for Québec without resulting in rate increases for our customers. We are actively participating in the Régie de l'énergie's process so that these guidelines can be produced as quickly as possible."

With this move, the government of Québec deviates from its decision to reportedly open the electricity market to miners at the end of last month, even as an Ontario-Quebec energy swap helps manage electricity demands. In March, the government said it was not interested in providing cheap electricity to Bitcoin miners, stating that cryptocurrency mining at a discount without any sort of “added value” for the local economy was unfavorable.

 

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