Ontario sending 200 workers to help restore power in Florida

Montana New Energy Economy integrates grid modernization, renewable energy, storage, and demand response to cut costs, create jobs, enable electric transportation, and reduce emissions through utility-scale efficiency, real-time markets, and distributed resources.

Key Points

Plan to modernize Montana's grid with renewables, storage and efficiency to lower costs, cut emissions and add jobs.

✅ Grid modernization enables real-time markets and demand response

✅ Utility-scale renewables paired with storage deliver firm power

✅ Efficiency and DERs cut peaks, costs, and pollution

Over the next decade, Montana ratepayers will likely invest over a billion dollars into what is now being called the new energy economy.

Not since Edison electrified a New York City neighborhood in 1882 have we had such an opportunity to rethink the way we commercially produce and consume electric energy.

Looking ahead, the modernization of Edison’s grid will lower the consumer costs, creating many thousands of permanent, well-paying jobs. It will prepare the grid for significant new loads like America going electric in transportation, and in doing so it will reduce a major source of air pollution known to directly threaten the core health of Montana and the planet.

Energy innovation makes our choices almost unrecognizable from the 1980s, when Montana last built a large, central-station power plant. Our future power plants will be smaller and more modular, efficient and less polluting — with some technologies approaching zero operating emissions.

The 21st Century grid will optimize how the supply and demand of electricity is managed across larger interconnected service areas. Utilities will interact more directly with their consumers, with utility trends guiding a new focus on providing a portfolio of energy services versus simply spinning an electric meter. Investments in utility-scale energy efficiency — LED streetlights, internet-connected thermostats, and tightening of commercial building envelopes among many — will allow consumers to directly save on their monthly bills, to improve their quality of life, and to help utilities reduce expensive and excessive peaks in demand.

The New Energy Economy will be built not of one single technology, but of many — distributed over a modernized grid across the West that approaches a real-time energy market, as provinces pursue market overhauls to adapt — connecting consumers, increasing competition, reducing cost and improving reliability.

Boldly leading the charge is a new and proven class of commercial generation powered by wind and solar energy, the latter of which employs advanced solid-state electronics, free fuel and no emissions or moving parts. Montana is blessed with wind and solar energy resources, so this is a Made-in-Montana energy choice. Note that these plants are typically paired with utility-scale energy storage investments — also an essential building block of the 21st century grid — to deliver firm, on-demand electric service.

Once considered new age and trendy, these production technologies are today competent and shovel-ready. Their adoption will build domestic energy independence. And, they are aggressively cost-competitive. For example, this year the company ISO New England — operator of a six-state grid covering all of New England — released an all-source bid for new production capacity. Unexpectedly, 100% of the winning bids were large solar electric power and storage projects, as coal and nuclear disruptions continue to shape markets. For the first time, no applications for fossil-fueled generation cleared auction.

By avoiding the burning of traditional fuels, the new energy technologies promise to offset and eventually eliminate the current 1,500 million metric tons of damaging greenhouse gases — one-quarter of the nation’s total — that are annually injected into the atmosphere by our nation’s current electric generation plants. The first step to solving the toughest and most expensive environmental issues of our day — be they costly wildfires or the regional drought that threatens Montana agriculture and outdoor recreation — is a thoughtful state energy policy, built around the new energy economy, that avoids pitfalls like the Wyoming clean energy bill now proposed.

Important potential investments not currently ready for prime time are also on the horizon, including small and highly efficient nuclear innovation in power plants — called small modular reactors (SMR) — designed to produce around-the-clock electric power with zero toxic emissions.

The nation’s first demonstration SMR plant is scheduled to be built sometime late this decade. Fingers are crossed for a good outcome. But until then, experts agree that big questions on the future commercial viability of nuclear remain unanswered: What will be SMR’s cost of electricity? Will it compete? Where will we source the refined fuel (most uranium is imported), and what will be the plan for its safe, permanent disposal?

So, what is Montana’s path forward? The short answer is: Hopefully, all of the above.

Key to Montana’s future investment success will be a respectful state planning process that learns from Texas grid improvements to bolster reliability.

Montanans deserve a smart and civil and bipartisan conversation to shape our new energy economy. There will be no need, nor place, for parties that barnstorm the state about "radical agendas" and partisan name calling – that just poisons the conversation, eliminates creative exchange and pulls us off task.

The task is to identify and vet good choices. It’s about permanently lowering energy costs to consumers. It’s about being business smart and business friendly. It’s about honoring the transition needs of our legacy energy communities. And, it’s about stewarding our world-class environment in earnest. That’s the job ahead.

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BC Tidal Energy Micro-Grids harness predictable tidal currents to replace diesel in remote Indigenous coastal communities, integrating marine renewables, storage, and demand management for resilient off-grid power along Vancouver Island and Haida Gwaii.

Key Points

Community-run tidal turbines and storage deliver reliable, diesel-free electricity to remote B.C. coastal communities.

✅ Predictable power from tidal currents reduces diesel dependence

✅ Integrates storage, demand management, and microgrid controls

✅ Local jobs via marine supply chains and community ownership

Many remote West Coast communities are reliant on diesel for electricity generation, which poses a number of negative economic and environmental effects.

But some sites along B.C.’s extensive coastline are ideal for tidal energy micro-grids that may well be the answer for off-grid communities to generate clean power, suggested experts at a COAST (Centre for Ocean Applied Sustainable Technologies) virtual event Wednesday.

There are 40 isolated coastal communities, many Indigenous communities, and 32 of them are primarily reliant on diesel for electricity generation, said Ben Whitby, program manager at PRIMED, a marine renewable energy research lab at the University of Victoria (UVic).

Besides being a costly and unreliable source of energy, there are environmental and community health considerations associated with shipping diesel to remote communities and running generators, Whitby said.

“It's not purely an economic question,” he said.

“You've got the emissions associated with diesel generation. There's also the risks of transporting diesel … and sometimes in a lot of remote communities on Vancouver Island, when deliveries of diesel don't come through, they end up with no power for three or four days at a time.”

The Heiltsuk First Nation, which suffered a 110,000-litre diesel spill in its territorial waters in 2016, is an unfortunate case study for the potential environmental, social, and cultural risks remote coastal communities face from the transport of fossil fuels along the rough shoreline.

A U.S. barge hauling fuel for coastal communities in Alaska ran aground in Gale Pass, fouling a sacred and primary Heiltsuk food-harvesting area.

There are a number of potential tidal energy sites near off-grid communities along the mainland, on both sides of Vancouver Island, and in the Haida Gwaii region, Whitby said.

Tidal energy exploits the natural ebb and flow of the coast’s tidal water using technologies like underwater kite turbines to capture currents, and is a highly predictable source of renewable energy, he said.

Micro-grids are self-reliant energy systems drawing on renewables from ocean, wave power resources, wind, solar, small hydro, and geothermal sources.

The community, rather than a public utility like BC Hydro, is responsible for demand management, storage, and generation with the power systems running independently or alongside backup fuel generators — offering the operators a measure of energy sovereignty.

Depending on proximity, cost, and renewable solutions, tidal energy isn’t necessarily the solution for every community, Whitby noted, adding that in comparison to hydro, tidal energy is still more expensive.

However, the best candidates for tidal energy are small, off-grid communities largely dependent on costly fossil fuels, Whitby said.

“That's really why the focus in B.C. is at a smaller scale,” he said.

“The time it would take (these communities) to recoup any capital investment is a lot shorter.

“And the cost is actually on a par because they're already paying a significant amount of money for that diesel-generated power.”

Lisa Kalynchuk, vice-president of research and innovation at UVic, said she was excited by the possibilities associated with tidal power, not only in B.C., but for all of Canada’s coasts.

“Canada has approximately 40,000 megawatts available on our three coastlines,” Kalynchuk said.

“Of course, not all this power can be realized, but it does exist, so that leads us to the hard part — tapping into this available energy and delivering it to those remote communities that need it.”

Challenges to establishing tidal power include the added cost and complexity of construction in remote communities, the storage of intermittent power for later use, the economic model, though B.C.’s streamlined regulatory process may ease approvals, the costs associated with tidal power installations, and financing for small communities, she said.

But smaller tidal energy projects can potentially set a track record for more nascent marine renewables, as groups like Marine Renewables Canada pivot to offshore wind development, at a lower cost and without facing the same social or regulatory resistance a large-scale project might face.

A successful tidal energy demo project was set up using a MAVI tidal turbine in Blind Channel to power a private resort on West Thurlow Island, part of the outer Discovery Islands chain wedged between Vancouver Island and the mainland, Whitby said.

The channel’s strong tidal currents, which routinely reach six knots and are close to the marina, proved a good site to test the small-scale turbine and associated micro-grid system that could be replicated to power remote communities, he said.

The mooring system, cable, and turbine were installed fairly rapidly and ran through the summer of 2017. The system is no longer active as provincial and federal funding for the project came to an end.

“But as a proof of concept, we think it was very successful,” Whitby said, adding micro-grid tidal power is still in the early stages of development.

Ideally, the project will be revived with new funding, so it can continue to act as a test site for marine renewable energy and to showcase the system to remote coastal communities that might want to consider tidal power, he said.

In addition to harnessing a local, renewable energy source and increasing energy independence, tidal energy micro-grids can fuel employment and new business opportunities, said Whitby.

The Blind Channel project was installed using the local supply chain out of nearby Campbell River, he said.

“Most of the vessels and support came from that area, so it was all really locally sourced.”

Funding from senior levels of government would likely need to be provided to set up a permanent tidal energy demonstration site, with recent tidal energy investments in Nova Scotia offering a model, or to help a community do case studies and finance a project, Whitby said.

Both the federal and provincial governments have established funding streams to transition remote communities away from relying on diesel.

But remote community projects funded federally or provincially to date have focused on more established renewables, such as hydro, solar, biomass, or wind.

The goal of B.C.’s Remote Community Energy Strategy, part of the CleanBC plan and aligned with zero-emissions electricity by 2035 targets across Canada, is to reduce diesel use for electricity 80 per cent by 2030 by targeting 22 of the largest diesel locations in the province, many of which fall along the coast.

The province has announced a number of significant investments to shift Indigenous coastal communities away from diesel-generated electricity, but they predominantly involve solar or hydro projects.

A situation that’s not likely to change, as the funding application guide in 2020 deemed tidal projects as ineligible for cash.

Yet, the potential for establishing tidal energy micro-grids in B.C. is good, Kalynchuk said, noting UVic is a hub for significant research expertise and several local companies, including ocean and river power innovators working in the region, are employing and developing related service technologies to install and maintain the systems.

“It also addresses our growing need to find alternative sources of energy in the face of the current climate crisis,” she said.

“The path forward is complex and layered, but one essential component in combating climate change is a move away from fossil fuels to other sources of energy that are renewable and environmentally friendly.”

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US Grid Pandemic Response coordinates control rooms, grid operators, and critical infrastructure, leveraging hydroelectric plants, backup control centers, mutual assistance networks, and deep cleaning protocols to maintain reliability amid reduced demand and COVID-19 risks.

Key Points

US Grid Pandemic Response encompasses measures by utilities and operators to safeguard power reliability during COVID-19

✅ Control rooms staffed on-site; operators split across backup centers

✅ Health screenings, deep cleaning, and isolation protocols mitigate contagion

✅ Reduced demand and mutual assistance improve grid resilience

Control rooms are the brains of NYPA’s power plants, which are mostly hydroelectric and supply about a quarter of all the electricity in New York state. They’re also a bit like human petri dishes. The control rooms are small, covered with frequently touched switches and surfaces, and occupied for hours on end by a half-dozen employees. Since social distancing and telecommuting isn’t an option in this context, NYPA has instituted regular health screenings and deep cleanings to keep the coronavirus out.

The problem is that each power plant relies on only a handful of control room operators. Since they have a specialized skill set, they can’t be easily replaced if they get sick. “They are very, very critical,” says Gil Quiniones, NYPA president and CEO. If the pandemic worsens, Quiniones says that NYPA may require control room operators to live on-site at power plants to reduce the chance of the virus making it in from the outside world. It sounds drastic, but Quiniones says NYPA has done it before during emergencies—once during the massive 2003 blackout, and again during Hurricane Sandy.

Meanwhile, PJM is one of North America’s nine regional grid operators and manages the transmission lines that move electricity from power plants to millions of customers in 13 states on the Eastern seaboard, including Washington, DC. PJM has had a pandemic response plan on the books for 15 years, but Mike Bryson, senior vice president of operations, says that this is the first time it’s gone into full effect. As of last week, about 80 percent of PJM’s 750 full-time employees have been working from home. But PJM also requires a skeleton crew of essential workers to be on-site at all times in its control centers. As part of its emergency planning, PJM built a backup control center years ago, and now it is splitting control center operators between the two to limit contact.

Past experience with large-scale disasters has helped the energy sector keep the lights on and ventilators running during the pandemic. Energy is one of 16 sectors that the US government has designated as “critical infrastructure,” which also includes the communications industry, transportation sector, and food and water systems. Each is seen as vital to the country and therefore has a duty to maintain operations during national emergencies.

“We need to be treated as first responders,” says Scott Aaronson, the vice president of security and preparedness at the Edison Electric Institute, a trade group representing private utilities. “Everybody's goal right now is to keep the public healthy, and to keep society functioning as best we can. A lack of electricity will certainly create a challenge for those goals.”

America’s electricity grid is a patchwork of regional grid operators connecting private and state-owned utilities. This means simply figuring out who’s in charge and coordinating among the various organizations is one of the biggest challenges to keeping the electricity flowing during a national emergency, according to Aaronson.

Generally, a lot of this responsibility falls on formal energy organizations like the nonprofit North American Electric Reliability Corporation and the Federal Energy Regulatory Commission. But during the coronavirus outbreak, an obscure organization run by the CEOs of electric utilities called the Electricity Subsector Coordinating Council has also served as a primary liaison between the federal government and the thousands of utility companies around the US. Aaronson says the organization has been meeting twice a week for the past three weeks to ensure that utilities are implementing best practices in their response to the coronavirus, as well as to inform the government of material needs to keep the energy sector running smoothly.

This tight-knit coordination will be especially important if the pandemic gets worse, as many forecasts suggest it will. Most utilities belong to at least one mutual assistance group, an informal network of electricity suppliers that help each other out during a catastrophe. These mutual assistance networks are usually called upon following major storms that threaten prolonged outages. But they could, in principle, be used to help during the coronavirus pandemic too. For example, if a utility finds itself without enough operators to manage a power plant, it could conceivably borrow trained operators from another company to make sure the power plant stays online.

So far, utilities and grid operators have managed to make it work on their own. There have been a handful of coronavirus cases reported at power plants, but they haven’t yet affected these plants’ ability to deliver energy. The challenges of running a power plant with a skeleton crew is partially offset by the reduced power demand as businesses shut down and more people work from home, says Robert Hebner, the director of the Center for Electromechanics at the University of Texas. “The reduced demand for power gives utilities a little breathing room,” says Hebner.

A recent study by the University of Chicago’s Energy Policy Institute found that electricity demand in Italy has plunged by 18 percent following the severe increase in coronavirus cases in the country. Energy demand in China also plummeted as a result of the pandemic. Bryson, at PJM, says the grid operator has seen about a 6 percent decrease in electricity demand in recent weeks, but expects an even greater drop if the pandemic gets worse.

Generally speaking, problems delivering electricity in the US occur when the grid is overloaded or physically damaged, such as during California wildfires or a hurricane.

An open question among coronavirus researchers is whether there will be a second wave of the pandemic later this year. During the Spanish flu pandemic in the early 20th century, the second wave turned out to be deadlier than the first. If the coronavirus remerges later this year, it could be a serious threat to reliable electricity in the US, says John MacWilliams, a former associate deputy secretary of the Department of Energy and a senior fellow at Columbia University’s Center on Global Energy Policy.

“If this crisis extends into the fall, we're going to hit hurricane season along the coasts,” MacWilliams says. “Utilities are doing a very good job right now, but if we get unlucky and have an active hurricane season, they're going to get very stressed because the number of workers that are available to repair damage and restore power will become more limited.”

This was a sentiment echoed by Bryson at PJM. “Any one disaster is manageable, but when you start layering them on top of each other, it gets much more challenging,” he adds. The US electricity grid struggles to handle major storms as it is, and these challenges will be heightened if too many workers are home sick. In this sense, the energy sector’s ability to deliver the electricity needed to keep manufacturing medical supplies or keep ventilators running depends to a large extent on our ability to flatten the curve today. The coronavirus is bad enough without having to worry about the lights going out.

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Maritime Link HVDC Transmission connects Newfoundland and Nova Scotia to the North American grid, enabling renewable energy imports, subsea cable interconnection, Muskrat Falls hydro power delivery, and lower carbon emissions across Atlantic Canada.

Key Points

A 500 MW HVDC intertie linking Newfoundland and Nova Scotia to deliver Muskrat Falls hydro power.

✅ 500 MW capacity using twin 170 km subsea HVDC cables

✅ Interconnects Newfoundland and Nova Scotia to the North American grid

✅ Enables Muskrat Falls hydro imports, cutting CO2 and costs

For the first time, electricity has been sent between Newfoundland and Nova Scotia through the new Maritime Link.

The 500-megawatt transmission line — which connects Newfoundland to the North American energy grid for the first time and echoes projects like the New England Clean Power Link underway — was tested Friday.

"This changes not only the energy options for Newfoundland and Labrador but also for Nova Scotia and Atlantic Canada," said Rick Janega, the CEO of Emera Newfoundland and Labrador, which owns the link.

"It's an historic event in our eyes, one that transforms the electricity system in our region forever."

'On time and on budget'

It will eventually carry power from the Muskrat Falls hydro project in Labrador, where construction is running two years behind schedule and $4 billion over budget, a context in which the Manitoba Hydro line to Minnesota has also faced delay, to Nova Scotia consumers. It was supposed to start producing power later this year, but the new deadline is 2020 at the earliest.

The project includes two 170-kilometre subsea cables across the Cabot Strait between Cape Ray in southwestern Newfoundland and Point Aconi in Cape Breton.

The two cables, each the width of a two-litre pop bottle, can carry 250 megawatts of high voltage direct current, and rest on the ocean floor at depths up to 470 metres.

This reel of cable arrived in St. John's back in April aboard the Norwegian vessel Nexans Skagerrak, after the first power cable reached Nova Scotia earlier in the project. (Submitted by Emera NL)

The Maritime Link also includes almost 50 kilometres of overland transmission in Nova Scotia and more than 300 kilometres of overland transmission in Newfoundland, paralleling milestones on Site C transmission work in British Columbia.

The link won't go into commercial operation until January 1.

Janega said the $1.6-billion project is on time and on budget.

"We're very pleased to be in a position to be able to say that after seven years of working on this. It's quite an accomplishment," he said.

This Norwegian vessel was used to transport the 5,500 tonne subsea cable. (Submitted by Emera NL)

Once in service, the link will improve electrical interconnections between the Atlantic provinces, aligning with climate adaptation guidance for Canadian utilities.

"For Nova Scotia it will allow it to achieve its 40 per cent renewable energy target in 2020. For Newfoundland it will allow them to shut off the Holyrood generating station, in fact using the Maritime Link in advance of the balance of the project coming into service," Janega said.

Karen Hutt, president and CEO of Nova Scotia Power, which is owned by Emera Inc., calls it a great day for Nova Scotia.

"When it goes into operation in January, the Maritime Link will benefit Nova Scotia Power customers by creating a more stable and secure system, helping reduce carbon emissions, and enabling NSP to purchase power from new sources," Hutt said in a statement.

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Germany January Power Mix shows gas-fired generation rising, coal steady, and nuclear phaseout impacts, amid cold weather, energy prices, industrial demand, and emissions targets shaping renewables, grid stability, and security of supply.

Key Points

The January electricity mix, highlighting gas, coal, renewables, and nuclear exit effects on emissions, prices, and demand.

✅ Gas output up 13% to 8.74 TWh, share at 18.6%.

✅ Coal share 23%, down year on year, steady vs late 2023.

✅ Nuclear gap filled by gas and coal; emissions below Jan 2023.

Germany's electricity generation in January presented a fascinating snapshot of its energy transition journey. As the country strives to move away from fossil fuels, with renewables overtaking coal and nuclear in its power mix, it grapples with the realities of replacing nuclear power and meeting fluctuating energy demands.

Gas Takes the Lead:

Gas-fired power plants saw their highest output in two years, generating 8.74 terawatt hours (TWh). This 13% increase compared to January 2023 compensated for the closure of nuclear reactors, which were extended during the energy crisis to shore up supply, and colder weather driving up heating needs. This reliance on gas, however, pushed its share in the electricity mix to 18.6%, highlighting Germany's continued dependence on fossil fuels.

Coal Fades, but Not Forgotten:

While gas surged, coal-fired generation remained below previous levels, dropping 29% from January 2023. However, it stayed relatively flat compared to late 2023, suggesting utilities haven't entirely eliminated it. Coal still held a 23% share, and periodic coal reliance remains evident, exceeding gas' contribution, reflecting its role as a reliable backup for intermittent renewable sources like wind.

Nuclear Void and its Fallout:

The shutdown of nuclear plants in April 2023 created a significant gap, previously accounting for an average of 12% of annual electricity output. This loss is being compensated through gas and coal, with gas currently the preferred choice, even as a nuclear option debate persists among policymakers. This strategy kept January's power sector emissions lower than the previous year, but rising demand could shift the balance.

Industry's Uncertain Impact:

Germany's industrial sector, a major energy consumer, is facing challenges like high energy prices and weak consumer demand. While the government aims to foster industrial recovery, uncertainties linger due to a shaky coalition and limited budget, and debate about a possible nuclear resurgence continues in parallel, which could reshape policy. Any future industrial revival would likely increase energy demand and potentially necessitate more gas or coal.

Cost-Driven Choices and Emission Concerns:

The choice between gas and coal depends on their relative costs, in a system pursuing a coal and nuclear phase-out under long-term policy. Currently, gas seems more favorable emission-wise, but if its price rises, coal might become more attractive, impacting overall emissions.

Looking Ahead:

Germany's energy transition faces a complex balancing act, with persistent grid expansion woes and exposure to cheap gas complicating progress. While the reliance on gas and coal highlights the difficulties in replacing nuclear, the focus on emissions reduction is encouraging. Navigating the challenges of affordability, industrial needs, and climate goals will be crucial for a successful transition to a clean and secure energy future.

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2022 US Renewable Power Milestone highlights EIA data: wind and solar outpaced coal and nuclear, hydropower contributed, with falling levelized costs, grid integration, battery storage, and transmission upgrades shaping affordable, reliable clean power growth.

Key Points

The year US renewables, led by wind and solar, generated more power than coal and nuclear, per EIA.

✅ Wind and solar rose; levelized costs fell 70%-90% over decade

✅ Renewables surpassed coal and nuclear in 2022 per EIA

✅ Grid needs storage and transmission to manage intermittency

Electricity generated from renewables surpassed coal in the United States for the first time in 2022, as wind and solar surpassed coal nationwide, the U.S. Energy Information Administration has announced.

Renewables also surpassed nuclear generation in 2022 after first doing so last year, and wind and solar together generated more electricity than nuclear for the first time in the United States.

Growth in wind and solar significantly drove the increase in renewable energy and contributed 14% of the electricity produced domestically in 2022, with solar producing about 4.7% of U.S. power overall. Hydropower contributed 6%, and biomass and geothermal sources generated less than 1%.

“I’m happy to see we’ve crossed that threshold, but that is only a step in what has to be a very rapid and much cheaper journey,” said Stephen Porder, a professor of ecology and assistant provost for sustainability at Brown University.

California produced 26% of the national utility-scale solar electricity followed by Texas with 16% and North Carolina with 8%.

The most wind generation occurred in Texas, which accounted for 26% of the U.S. total, while wind is now the most-used renewable electricity source nationwide, followed by Iowa (10%) and Oklahoma (9%).

“This booming growth is driven largely by economics,” said Gregory Wetstone, president and CEO of the American Council on Renewable Energy, as renewables became the second-most prevalent U.S. electricity source in 2020 nationwide. “Over the past decade, the levelized cost of wind energy declined by 70 percent, while the levelized cost of solar power has declined by an even more impressive 90 percent.”

“Renewable energy is now the most affordable source of new electricity in much of the country,” added Wetstone.

The Energy Information Administration projected that the wind share of the U.S. electricity generation mix will increase from 11% to 12% from 2022 to 2023 and that solar will grow from 4% to 5% during the period, and renewables hit a record 28% share in April according to recent data. The natural gas share is expected to remain at 39% from 2022 to 2023, and coal is projected to decline from 20% last year to 17% this year.

“Wind and solar are going to be the backbone of the growth in renewables, but whether or not they can provide 100% of the U.S. electricity without backup is something that engineers are debating,” said Brown University’s Porder.

Many decisions lie ahead, he said, as the proportion of renewables that supply the energy grid increases, with renewables projected to soon be one-fourth of U.S. electricity generation over the near term.

This presents challenges for engineers and policy-makers, Porder said, because existing energy grids were built to deliver power from a consistent source. Renewables such as solar and wind generate power intermittently. So battery storage, long-distance transmission and other steps will be needed to help address these challenges, he said.

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