Washington state lifted its remaining drought designations last week because of an unexpectedly cool and wet May and June.
The unseasonably cool weather has caused Cascade Range snowpack to last longer into the summer, which will support late-summer water needs, Jeff Marti, statewide drought coordinator at Washington’s Department of Ecology, said in a statement.
“Conditions have improved. All areas of the state, including the five watersheds specified in the drought declaration, have received significantly above-normal precipitation,” Marti said. “The outlook is much better than forecast back in May.”
The wet weather doubled the normal June rainfall figures for much of Eastern Washington. “Conditions have been anything but drought-like,” Marti said. “We’ve experienced one of the wettest, coldest springs in recent memory.”
In July 2021, Gov. Jay Inslee declared a drought emergency for 96% of the state, citing the severe effects of climate change. Last year’s declaration sped up processing for emergency drought permits and allowed temporary transfers of water rights. The cities of Seattle, Tacoma and Everett were not included in the drought emergency because they have significant amounts of stored water.
On May 26, the area of Washington from the Cascades to the west was removed from the drought designation. Most of Eastern Washington, except for four areas, was designated as a drought advisory area. A “drought advisory” means that rainfall is above the 75% mark but could potentially drop below.
In May, five watersheds in areas spread across parts of eight northeastern counties were still in “drought emergency” because they had not received enough rainfall to recover. This land covers about 9% of the state. The drought emergency area covered parts of Spokane, Lincoln, Grant, Adams, Whitman, Stevens, Okanogan and Pend Oreille counties.
The lifting of drought designations addresses those Eastern Washington areas.
The U.K.-based Space Energy Initiative has set its sights on commercializing space-based solar power (SBSP) by 2035 as a renewable baseload option for the global effort to reach net-zero-emissions energy.
SBSP as a concept is not new, but interest in the technology has been stymied by technological and financial limitations. David Homfray, technical lead for the SEI, says those factors are changing in ways that now make SBSP deployment more viable.
The UK-based Space Energy Initiative wants to deploy solar energy technology in space by 2035 that can capture light perpetually and transmit it to Earth. | Satellite Applications Catapult
“Space-based solar power is a massive challenge; it’s going to be similar to an Apollo mission,” he said during a July 12 webinar hosted by Satellite Applications Catapult, one of Innovate UK’s research and development centers.
The catapult is a founding member of SEI, which has grown to a 50-member organization that established working groups to develop SBSP over the next 12 years, said Homfray, who is also space energy lead at SEI. Members of the initiative include U.S.-based Teledyne Technologies and KBR.
“The Americans are extremely invested in this, and we’re working in China and Japan, and Australia and Europe are interested as well,” he said.
The approach SEI is focusing on would require launching a spacecraft that is larger but lighter than the International Space Station (357 feet) and has big mirrors affixed to it. Sunlight would reflect off the mirrors onto photovoltaic modules and be transformed into radio waves. A transmitter would then send those waves to grid-connected ground receivers that take up about the same amount of space as an average solar array.
Deployment of the technology in space means the satellites could capture light perpetually, unlike their land-based counterparts.
Here are three things Homfray says about SBSP: as an option for net-zero, why it’s viable now and what SEI’s development timeline looks like.
Why SBSP?
Reaching net-zero energy by 2050 presents a unique set of challenges, not the least of which is the pace at which change must occur.
“By 2050, we need to have replaced around 40 billion MWh, and with around 10,000 days to do it, that would be about 4 MWh a day,” Homfray said. Collecting solar in space, he added, would provide 13 times as much energy as is generated from solar technology on average today.
SBSP is not the only clean energy solution needed for the net-zero transition, but SEI’s members believe it can be an important part of it.
The initiative, therefore, aims to demonstrate that deploying solar in space as a baseload power solution will be affordable, reliable and scalable.
Why Now?
Traditionally, launching a spacecraft is very expensive, reaching $65,000/kg, according to Homfray. However, potential commercialization by companies like SpaceX and Blue Origin is going to bring per-launch costs down.
“If SpaceX develops their Starship, or similar companies develop fully reusable, heavy-launch vehicles, then we really are talking about being able to lift quite heavy mass” for each launch, he said.
Lowering launch costs will be critical for SBSP, which would require many launches to bring parts to space for construction.
“Space-based solar power should be more thought of as being a mobile phone producer than it is as large spacecraft,” Homfray said. “We’re going to build lots of modules, and we’re going to assemble them in space.”
Application of terrestrial-based solar technology to the SBSP concept also is helping the initiative lower its estimated project costs.
SEI expects the cost of building a SBSP facility to be less than a new nuclear facility.
Costs aside, SBSP will only reach its potential through deployment of a fleet of satellites, which Homfray said will require ongoing initiatives focused on making the space industry sustainable.
What’s the Timeline?
SEI has built a 12-year SBSP program that is divided into four phases.
The first phase is dedicated to de-risking the technology so “there are no fundamental technological challenges in our way,” Homfray said. In phase 2, the initiative will deploy demonstration projects with a goal of producing 6 MW of solar power from space.
SEI will work on commercializing SBSP in phases 3 and 4.
“In phase 3, we’ll put around about a 180-MW spacecraft up there … and phase 4 is where the technology is industrialized; it’s all about gigafactories and manufacturing throughput,” Homfray said.
If the plan succeeds, he added, SBSP can access a $5 trillion/year energy market and “inspire the next generation to take part in this net-zero race.”
MISO this week responded to blistering criticism from Illinois lawmakers, insisting that it and its members “fully understand the need for urgency when it comes to building new transmission and adding new generation to the electric grid.”
“It is important to remember that MISO since its inception has been by design and by rule both fuel agnostic and policy neutral,” the grid operator said in a statement to RTO Insider. “Our responsibility is to maintain a reliable electric grid and manage one of the world’s largest energy markets through collaboration with state officials and member utilities seeking to accomplish their energy goals and strategies. This includes supporting the clean energy goals of our states and member utilities.”
MISO pointed out that it has in total interconnected about 30 GW of wind generation and 2 GW of solar generation across its footprint. It said it has acted with resolve to shorten the time it takes for it to study, assign system upgrades and interconnect developers’ new generation through its interconnection queue.
Two Illinois lawmakers who sponsored the state’s Climate and Equitable Jobs Act held a press conference last week to criticize MISO over failing to bring renewable energy in its interconnection queue online to solve its current capacity deficiency. (See Illinois Leaders Blast MISO Inaction on Capacity Crisis.)
Also last week, the Illinois Commerce Commission (ICC) opened a docket directing Ameren Illinois to perform a cost-benefit analysis of remaining in MISO versus departing for PJM or another grid operator (22-0485). The ICC gave Ameren a year to produce the study and said it should cover between five and 10 years from mid-2024, focusing on “reliability, resource adequacy, resiliency, affordability, equity and the impact on the environment, and the general health, safety and welfare of the people of Illinois.”
Chair Carrie Zalewski said the ICC feels it “appropriate to explore whether membership in MISO continues to provide net benefits to Ameren Illinois’ electricity customers.”
MISO said it was “not invited to nor made aware” of the legislators’ press conference.
“We are always available to meet with public officials and provide independent facts and information to help them better understand our industry. This collaboration and information exchange has never been more vital, especially as we work together towards providing consumers with low-cost, uninterrupted power now and in the future,” the RTO said.
The grid operator disputed the legislators’ claim that 34 generation projects from the state wait in the queue. MISO said it’s in fact processing 95 generation interconnection requests totaling more than 15 GW for the state.
“MISO is and continues to be ‘on the job’ of ensuring reliability is maintained while managing through this unprecedented number of unique requests to connect new resources,” it said.
The RTO said that since 2015, it has connected about 2.1 GW worth of new wind and solar resources in Illinois. It said it has also approved another 4.4 GW of renewable energy and natural gas generation that is now just waiting on completion by developers. The grid operator insisted that its interconnection process “continues to be one of the most efficient in the electricity industry.”
MISO also said that $1.6 billion worth of projects from its recently approved $10.3 billion long-range transmission plan (LRTP) will be built in Illinois. (See MISO Board Approves $10B in Long-Range Tx Projects.) It added that an additional $445 million of new transmission approved through its annual MISO Transmission Expansion Plan cycles is set to come online by 2025.
“All this investment will help support Illinois’ state energy policy objectives,” the grid operator said.
Persistent triple-digit temperatures and extreme heat warnings across much of Texas forced ERCOT on Sunday to issue yet another operating condition notice (OCN) as it continues to flirt with the 80-GW threshold.
The Texas grid operator said the OCN, its lowest-level market communication, was necessary because of forecasted temperatures above 103 degrees Fahrenheit in its North Central and South Central weather zones. The seventh OCN issued this summer, the notice was effective Monday until Wednesday.
Extreme heat will still be an issue in Texas and Oklahoma this week. | National Weather Service
Average demand Monday peaked at 78.8 GW during the hour ending at 5 p.m. CT. Staff expect demand Tuesday to just exceed 79 GW.
ERCOT has already set 11 new highs for peak demand this summer, the latest coming Wednesday when load came within 12 MW of breaking the 80-GW barrier. Demand averaged 79.8 GW during the hour ending at 5 p.m. CT.
Demand’s average peak has been above 70 GW every day since June 30. Before this year, ERCOT’s record peak was 74.8 GW, set in August 2019.
The National Weather Service said “sizzling” temperatures will stick around in the South Central U.S. before cooling off into the high 90s. Austin is expecting highs above 100 F into next week.
SPP Cancels Resource Advisory
SPP canceled a resource advisory for Monday, saying its forecast indicated more favorable conditions than originally anticipated. The RTO said it expected lower regionwide power usage and improved system capacity conditions.
“This summer has really put us the to the test,” CEO Barbara Sugg told SPP’s Regional State Committee on Monday.
The RTO’s most recent conservative operations and resource advisories expired as scheduled Thursday night.
SPP set a new mark for peak demand last week at 53.2 GW on July 19. It was the sixth time since July 5 the RTO has recorded a new high. The record before this year was 51.04 GW, set last July.
SAN DIEGO — The effort to limit global warming to 1.5 degrees Celsius will require a nearly half-and-half energy mix of renewable electricity and “clean molecules” such as hydrogen, according to Yuri Freedman, senior director of business development at Southern California Gas.
Drawing on research by BloombergNEF, Freedman spoke last week on a “Transforming the Gas System with Hydrogen” panel at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit. Notably, the panel lacked any skeptics about a big role for natural gas companies — or hydrogen — in the decarbonization of the U.S. energy system.
“Molecules are as critical” as electrons in getting to a zero-emissions world, Freedman said.
“Today, we consume 80% of our energy as molecules, so 80/20 is the makeup today,” he said. “One implication of that: Think about what needs to happen if the share of electricity is going to go from 20% to 50%” — an increase of 250%.
“But the molecules we’ll need tomorrow are different [from those used today], so you actually need to find a way to phase out the molecules that produce carbon emissions and introduce at scale those molecules by 2050 that are going to have no emissions,” Freedman said.
Compared with other potential substitutes for natural gas (such as biomethane), hydrogen has the greatest potential to be adopted at scale in the next few years and can do most of what natural gas does today, Freedman said, including being used to power fuel cell electric vehicles.
“When I hear the debate, ‘Should it be battery or fuel cell’ … well fuel cell [vehicles] are electric vehicles. In fact, they often can be assembled at the same factory as the battery electric vehicles,” Freedman said.
SoCalGas foresees hydrogen being used in three different sectors in Southern California.
The first is power generation, based on plans by the Los Angeles Department of Water and Power to convert a number of its generation stations to a blend of natural gas and green hydrogen, followed by a full conversion to hydrogen to meet California’s emissions targets.
The second is transportation, with Freedman noting that about 20,000 trucks haul goods between the ports of Long Beach and Los Angeles.
“These trucks go through neighborhoods which are often low-income neighborhoods, so [it’s] not just the greenhouse gas emissions, but the air quality impact is very heavy. And we can be a significant director of environmental and social justice with the replacement of these diesel trucks with fuel cells,” Freedman said.
The third sector is manufacturing. “Los Angeles happens to be the largest manufacturing area in the country. That’s not typically what L.A. is associated with, but that’s the reality,” he said.
‘Not an Aspiration’
Panelist Jeff Reed is chief scientist for renewable fuels and energy storage at the Advanced Power and Energy Program at University of California, Irvine. He also previously worked at SoCalGas parent company Sempra Energy.
“From 2010 until I left Sempra in 2018, I was focusing on the leading edge of what Yuri is talking about: How do you decarbonize a gas utility? And in the state of California, that’s not an aspiration; that’s statute; that’s law; we must do that. So it’s really increased our efforts in this area,” Reed said.
Reed’s work initially focused on replacing natural gas with biomethane, which he called a “very important resource for the leading edge of the decarbonization process.”
But the evolving science around producing hydrogen means that fuel can potentially be produced at the price and quantities needed to replace fossil fuels, he said.
Around $6/kg — or $40/MMBtu — electrolytic hydrogen produced from renewables (green) is still expensive compared with hydrogen produced by the steam methane reformation (blue), which requires the resulting carbon emissions to be captured in order to be considered emissions-free.
But technological advancements also mean that green hydrogen “really does have the potential to have a rather steep cost-reduction curve, similar to what we’ve seen with wind and solar energy.”
Reed thinks the U.S. Department of Energy’s “Earthshot” goal of achieving $1/kg green hydrogen is a “stretch, but not impossible.”
“Once you get to a certain cost point, you can envision using hydrogen or renewable methane, for everything we currently use natural gas for. If we’re using hydrogen, we can also add a substantial additional demand for mobility and transport, which isn’t currently served by the natural gas system,” Reed said.
He noted that California policy currently assumes electric air-source heat pumps are the most efficient way to heat buildings.
“If we get near these Earthshot goals, that’s actually not the case. You can provide heating in the same way we do with natural gas, and be very cost-competitive,” he said.
Question of Cost
New Jersey Board of Public Utilities Commissioner Upendra Chivukula said his state is excited to be part of an effort to win part of $8 billion in DOE funding to become a national hydrogen hub, in partnership with New York, Connecticut and Massachusetts. (See DOE Hydrogen HUB Funding Program Announced.)
“The [New Jersey] legislature and governor are excited about hydrogen, and, of course, utilities have reached out to the commission, and they already started blending hydrogen into natural gas,” Chivukula said. “But the question is the cost, I think. Who’s going to pay for the cost?
“We look at hydrogen as promising, but it is going to take some time. The costs have to come down, and some of the technological advancements have to take place,” he said. “So we are looking forward to more on hydrogen, because I don’t know whether we’ll be able to get 100% clean energy with electrification alone.”
“What would allow those costs to come down,” Massachusetts Department of Public Utilities Commissioner Robert Hayden, co-moderator of the discussion, asked panelists.
Reed responded that natural gas-derived hydrogen can already be produced fairly cheaply at less than $2/kg, but it requires pipelines for the transportation and sequestration of carbon emissions. Regarding green hydrogen, he reiterated his comparison to solar development, where a high “demonstrated learning rate” has significantly reduced costs in the past decade. “So what we need is production volumes and global expansion in the market,” he said.
For Freedman, cost reductions will come down to building pipelines dedicated to transporting hydrogen.
“The majority of that cost is not production; the vast majority comes from the fact that they have to put it in a truck and haul it in cylinders, and that’s not cheap. So a pipeline is an absolute must to that low cost of hydrogen,” Freedman said.
Speaking from the audience, North Carolina Utilities Commissioner Floyd McKissick Jr. asked about the impact of DOE’s hydrogen hubs once they become operational.
“You can view these as a very exciting opportunity for us to catch up and maybe surpass where we think Europe is,” Freedman said.
Freedman envisions hub developments playing out “region by region,” given that some will be producing hydrogen from natural gas, while others will rely on renewables or nuclear power to generate hydrogen from water. But he does foresee the hubs becoming clusters of decarbonized industrial activity to overcome the issue of supplying hydrogen to multiple sectors.
The panel’s other moderator, Georgia Public Service Commissioner Tricia Pridemore, asked whether the “hydrogen rainbow” — using colors to refer to how the gas is produced — is still relevant.
“Within the trade groups that I work with, we really think we should be talking about carbon intensity, as our objective to a large extent is just to reduce carbon content in the gas system,” Reed said.
MISO’s Board of Directors voted unanimously Monday to approve the 18-project, $10.3 billion first phase of its long-range transmission plan (LRTP).
MISO Director Todd Raba called the July 25 open session of the board “one of the most important meetings” of his tenure.
MISO Vice President of System Planning Aubrey Johnson called it a “distinct honor” to summarize the plan a final time before the board greenlit it.
He said the portfolio will help MISO members ensure they can achieve their clean energy goals, “accommodate the rapid portfolio shift that’s well underway” and shore up the system as more extreme weather lashes the footprint.
Most of the projects’ routes use existing rights of way from other lines. The grid operator estimates the lines will be in service between 2028 and 2030 and deliver at least $37 billion in benefits to ratepayers from 2030 to 2050. The first LRTP portfolio is considered a late insert to MISO’s 2021 Transmission Expansion Plan. (See MISO Puts Finishing Touches on $10B Tx Plan, Hunts New Projects.)
To shape the transmission plan, MISO held more than 200 public stakeholder meetings over two years, some of them standing room only, Johnson said.
The portfolio is premised on MISO’s estimate that 58 GW of primarily coal resources will retire in the footprint within two decades, while the RTO adds 90 GW in solar, wind and natural gas generation, bringing its total installed capacity to about 160 GW.
MISO said the lines will result in a minimum 2.2-to-1 benefit-to-cost ratio across all its Midwestern transmission planning zones. MISO didn’t analyze its South region’s transmission needs for the portfolio and won’t for at least a year.
More ‘Urgency’ Needed
Several stakeholders took advantage of an open comment period at the end of the meeting to urge MISO to get a jump on more future-looking system planning.
Clean Grid Alliance’s Natalie McIntire said the need for the lines has never been more evident than during this heatwave-laced summer, when MISO strained to manage increased demand.
“This is not the time to stop planning. … It is just the first step in much-needed investment in transmission capacity nationwide,” she said. “We have more work to do to fully achieve carbon reduction goals and build a more resilient grid to withstand increased weather-related challenges.”
“Not only does MISO need this, but our nation needs this as a model,” Sustainable FERC Project Attorney Lauren Azar told MISO directors.
Azar urged MISO not to waste any time in planning the second, third and fourth iterations of the portfolio.
Invenergy’s Arash Ghodsian asked that MISO consider high-voltage merchant transmission planning, including the Grain Belt Express, in future long-range modeling and analysis. (See Invenergy Announces Grain Belt Express Expansion.) He called for a “more comprehensive and realistic view of the future system.”
MISO’s Environmental Sector said the portfolio is “critical, but there is far more leadership and urgency needed from MISO.
“Much more remains to be done to shift away from fossil fuels and quickly meet clean energy goals. Note that none of the benefits [in the portfolio] is being provided to residents and businesses in MISO South, which includes Louisiana, Arkansas, Mississippi, and a portion of Texas. The South is left out in this set of projects, despite the region’s dire need for greater resilience, clean energy deployment, and access to low-cost power,” the group said in a statement released ahead of the vote.
Environmental Sector members said MISO has been “subject to pressure from utilities like Entergy in the South — and others in the North — that have succeeded in delaying progress on long-range transmission lines.”
They said the “status quo, fossil-fuel-heavy” MISO grid is costing consumers, noting that about 500 solar, wind and hybrid project proposals have withdrawn from the MISO queue in the last five years.
The Union of Concerned Scientists (UCS) said the portfolio is a “significant first step toward building the modern, resilient, and reliable electric transmission system necessary to decarbonize the energy sector.” The group estimated that the lines will enable enough renewable energy to power more than 12 million homes.
James Gignac, senior Midwest energy analyst at UCS, called the vote “exciting progress, and only the first of several portfolios of investment that we’ll need to keep up with the drive to decarbonize and meet the challenges of climate change.”
MISO estimates the portfolio will keep 400 million metric tons of carbon emissions out of the atmosphere between 2030 and 2050.
“We appreciate the spirit of collaboration and the hard work that MISO members and stakeholders have invested in these projects and look forward to continued discussion around future tranches,” MISO CEO John Bear said in a statement following the vote. “We also recognize the effort and strong support for LRTP from various regulators and policymakers in the states — including state utility commissions and governors.”
The new portfolio is already at the heart of one FERC complaint. Last week, an alliance of consumer groups jointly filed to challenge MISO’s practice of respecting state rights of first refusal (ROFR) laws in its regional transmission planning. The consumer alliance asked FERC to block MISO and other RTOs from applying “anticompetitive” state ROFR laws to their regional transmission planning, including the long-range portfolio. (See related story, Consumer Groups File FERC Complaint Against MISO.)
MISO estimates just $1 billion of its $10.3 billion LRTP portfolio will ultimately be open to competition. The grid operator said nearly $4 billion worth of the projects are considered upgrades to existing facilities, while another $5.5 billion worth of projects will be sited in states that have enacted ROFR legislation.
Tx to Bring Capacity Online, but Will it Solve Crisis?
The transmission approval also comes as MISO is facing heightened scrutiny from its Midwestern states over a capacity shortage in the entire MISO Midwest region, which some say is partly due to insufficient transmission to connect the 806 mostly renewable projects totaling 126.3 GW in its interconnection queue.
The Organization of MISO States is considering the Independent Market Monitor’s recommendation that MISO replace its vertical capacity demand curve with a sloped curve to incent new resources. (See MISO Warming to Patton’s Sloped Demand Curve.) In a July 18 OMS board meeting, Executive Director Marcus Hawkins said OMS members heard a “menu of options” on auction and energy market changes during closed-door meetings during MISO’s June Board Week in Indianapolis.
And the Illinois Commerce Commission (ICC) last week directed Ameren Illinois to perform a cost-benefit analysis of remaining in MISO versus departing for PJM or another grid operator (22-0485). Chair Carrie Zalewski said the ICC feels it “appropriate to explore whether membership in MISO continues to provide net benefits to Ameren Illinois’ electricity customers.”
Citizens Utility Board of Michigan Executive Director Amy Bandyk called it “good news that MISO is overcoming barriers that have blocked new transmission lines for years. A more connected grid benefits ratepayers by enabling lower-cost renewable energy to flow to where it is needed, improving the reliability of electric service.”
SAN DIEGO — Nuclear proponents pitched their plans for smaller and more innovative reactors at the National Association of Regulatory Utility Commissioners’ (NARUC) Summer Policy Summit on Wednesday, saying nuclear power is needed to provide a dependable source of carbon-free energy as coal plants retire, and wind and solar resources proliferate.
Chris Levesque, CEO of TerraPower — a company founded by Bill Gates — described the firm’s plans to develop a sodium-cooled reactor, paired with molten salt energy storage, near a PacifiCorp coal plant in southwest Wyoming slated to close in 2025. (See Wyoming Welcomes DOE-funded Advanced Nuclear Plant.)
In coming decades, “we’re going to retire all that 24/7 coal, and we’re going to add all this low-cost wind and solar, which is great, but it is intermittent” based on weather, Levesque said. “So, it’s really calling for nuclear, which we all believe … should be 20 to 30% of the carbon-free grid.”
In addition to the reactor’s baseload power, molten salt storage can ramp up quickly to meet peak demand, he said.
Levesque was one of four panelists in a session titled “Are We Ready for a Nuclear Reactor Renaissance?” and moderated by NARUC President Judith Jagdmann, a member of Virginia’s State Corporation Commission.
Jacob DeWitte — CEO and co-founder of Oklo Inc., a Silicon Valley startup aiming to build liquid-metal microreactors — said the company had secured a site license and fuel allocation from the Department of Energy to build its first compact fast reactor at the Idaho National Laboratory near Idaho Falls.
However, the Nuclear Regulatory Commission denied Oklo’s application in January, citing insufficient information. DeWitte said the company is continuing to press its case with the commission.
The compact modular units Oklo envisions could run for 20 years without refueling, DeWitte said, and would be housed inside buildings that look like futuristic ski chalets. Industry and rural communities could one day be Oklo’s customers, he said.
A rendering shows the exterior of Oklo’s proposed microreactor at the Idaho National Laboratory. | Oklo
“You have this kind of decentralized, dispatchable clean asset that all of a sudden, a lot of people in the industrial [and] commercial markets are pretty interested in for behind-the-meter generation,” he said. “You see a lot of appetite in different electric utility markets, ranging from the rural and the off-grid kind of co-ops and municipal utilities, to the larger-scale utilities, especially when you think about a system like this and what it can do for alleviating transmission stresses across a large grid like you have in the Western United States.”
Nuclear Energy Institute CEO Maria Korsnick called nuclear, currently the largest source of carbon-free energy in the U.S., critical to decarbonizing the grid.
“Our current reactors provide unmatched resiliency, which is the necessary foundation for a stable and affordable electric grid,” Korsnick said. “But that alone won’t be enough. In order for our communities and our economy to rise to these growing challenges, we must prepare our supply chain to build new, advanced reactor designs in the coming years.”
Reactors under development are “simpler and more adaptable to a variety of energy needs,” she said. “They will open new possibilities for carbon-free energy service at any scale, from the world’s largest cities to remote rural communities. And they can free communities from diesel and fossil fuels and require far less investment in transmission and distribution than other carbon-free resources.”
Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille said that may be true, but she asked how nuclear advocates planned to convince a wary public to accept more nuclear plants and the risk of catastrophic accidents. She grew up in Middletown, Pa., the closest community to the Three Mile Island nuclear generating station, which partially melted down in March 1979.
“In the course of the conversation and talking about this advanced technology, how do you sell it to the consumer who may be concerned about building more nuclear even though they also see the value of nuclear?” she said.
Korsnick said “nuclear favorability” in the U.S. is about 60%, and a recent survey among those who live near nuclear plants showed nearly 80% favorability, she said. The assumption that nuclear is widely despised is a result of decades of successful campaigns by anti-nuclear groups, she said.
Earlier in the session, Jeffrey Merrifield — a former member of the NRC and partner at law firm Pillsbury Winthrop Shaw Pittman in D.C. — asked for a show of hands from attendees who had slept a mile from a nuclear reactor. A spattering of audience members raised their hands.
Merrifield said everyone should have raised their hands because a nuclear aircraft carrier was docked in San Diego Bay, just across a narrow stretch of water from the hotel where the conference was being held. The supercarrier USS Carl Vinson’s twin “200-MW nuclear reactors … are 40 years old and speed millions of miles around the earth,” he said.
Assembled in factories, the compact units are among “100 reactors owned and operated by the U.S. Navy, modular reactors that power our nation’s 10 nuclear aircraft carriers and a multiplicity of subs,” Merrifield said. The units have “an incredible track record, and what we’re trying to talk about today with these developers is using that same methodology to bring these technologies to the American people.”
New Jersey on Monday launched the third phase of its Charge Up New Jersey electric vehicle (EV) subsidy program, cutting the maximum vehicle incentive to $4,000 but adding a new $250 subsidy for home chargers.
State officials said the incentive would apply to EV purchases beginning July 25 and would remain available until the $35 million in funding is exhausted. They also said they would begin accepting applications for three other programs that offer incentives to promote the use of EVs. Those programs pay for the installation of charging stations in tourist areas and multi-dwelling properties and help local and state governments add EVs to their fleets.
Speaking at a press conference in Asbury Park, Gov. Phil Murphy said the program, shows “our continued commitment to transitioning our economy away from fossil fuels.
“We know this incentive can push more buyers to making the decision to go electric,” said Murphy. The incentives will be especially effective, he said, “as the prices of EVs continue to fall more and more in line with gas-powered cars, especially in the all-important and growing mid-price category.”
The first two phases of Charge Up New Jersey, which is run by the Board of Public Utilities, assisted the purchase of about 13,000 vehicles.
Seeking ‘Incentive Essential’ Buyers
The new $250 incentive will be available for Level-Two chargers capable of capturing data, known as “smart” or “networked” chargers. The incentive will pay for chargers installed in a residence and will only cover equipment, not installation costs. The state budget approved in June allocated $5.5 million for the incentives.
At the same time, the BPU reduced by $1,000 the maximum EV incentive, from the $5,000 offered in the second phase. As before, the maximum incentive is only available for vehicles that cost $45,000 or less. Vehicles priced between $45,000 and $50,000 are eligible for an incentive of up to $2,000, and no subsidy will be awarded for higher priced vehicles.
The incentive is calculated by multiplying $25 by the number of miles that the vehicle will run on a single charge. For example, a 2021 Hyundai Kona Electric, which can run for about 258 miles on a single charge, according to the U.S. Environmental Protection Agency’s fueleconomy.gov site, would be eligible for the maximum $4,000 incentive.
The BPU implemented the $45,000 price-tag cap in the second phase after data showed that Tesla vehicles received 83% of the incentives in the first phase. The reduction meant that in the second phase only the lowest priced Tesla could get the maximum incentive. BPU officials said they believed that change would help the program focus on “incentive essential” customers: those who would only buy an EV if there was an incentive available. (See NJ Boosts EV Charging Program for Tourist, Multifamily Locations.) Indeed, data from the second phase show that Teslas accounted for 66% of the incentives granted.
Murphy noted that the available funds were quickly exhausted in the first two phases of the program.
“We expect more of the same this year,” Murphy said. “And with a refocusing of this incentive for mid-priced vehicles, we believe we can expand the appeal of an electric vehicle to more consumers.”
Expanding Charger Numbers
The EV incentive is part of a portfolio of programs aimed at helping the state meet the goals set out in the Energy Master Plan for the state to deploy 330,000 light-duty EVs on the road by 2025.
Slightly more than 64,000 EVs were registered to drive on New Jersey roads at the end of 2021, and there are about 750 chargers in the state.
The state in January 2020 enacted a law that called for the installation of at least 400 DC fast chargers, which can add about 60 to 80 miles to an EV in 20 minutes of charging, and 1,000 Level 2 chargers, which add 10 to 20 miles per hour of charging time, by Dec. 31, 2025.
New Jersey officials say the key to putting more EV vehicles on the road is to have more chargers available.
“We don’t want anybody to say ‘I’m not buying an electric vehicle because there’s not enough charging stations,” said BPU President Joseph L. Fiordaliso at the conference Monday.
To that end, New Jersey’s budget struck in June allocated $10 million to support the purchase of EVs by state and local governments, $6 million to put chargers at tourist sites and $4 million to put them in multi-unit dwellings.
The state agency drawing up California’s plan to reach carbon neutrality by 2045 should take “even bolder action” to address climate change, Gov. Gavin Newsom said on Friday.
The California Air Resources Board (CARB) should include in its climate plan a goal of at least 20 GW of offshore wind by 2045 and a target of 7 million “climate-friendly” homes in the state by 2035, Newsom said. The state has about 14.5 million housing units, according to census data.
Newsom said he’s asking state agencies to plan for a clean energy transition without new natural gas plants. And he asked CARB to set a carbon removal goal of 20 million metric tons (MMT) for 2030 and 100 MMT for 2045.
“We know from the Intergovernmental Panel on Climate Change that there is no path to carbon neutrality without carbon capture and sequestration,” Newsom said in the letter sent to CARB Chairwoman Liane Randoph.
CARB lays out a roadmap for the state to meet its climate goals in a document called the scoping plan. Under state law, the scoping plan must be updated every five years. The next edition is due by the end of this year.
A draft version of the scoping plan was released in May and presented to the CARB board last month. Although CARB analyzed ways to get the state to carbon neutrality by 2035, the draft plan’s selected scenario has the state reaching carbon neutrality in 2045. Some critics have called the proposed scoping plan “too little, too late.” (See Critics Tear into CARB Draft Climate Change Plan.)
‘More Aggressive Actions’
In his letter to Randolph, Newsom called the draft plan “the world’s first large-economy plan for carbon neutrality.” He said CARB’s final scoping plan must lay out a path to statewide carbon neutrality by 2045 as well as meeting the state’s 2030 climate goals. California’s 2030 target is a 40% reduction in greenhouse gas emissions compared to 1990 levels.
“The state’s draft carbon neutrality road map doesn’t go far enough or fast enough,” Newsom said Friday in a release. “That’s why I’m pushing state agencies to adopt more aggressive actions, from offshore wind to climate-friendly homes, and to make sure we never build another fossil fuel power plant in California again.”
Newsom asked that CARB incorporate his goals into the scoping plan.
Regarding offshore wind, Newsom said he would ask the California Energy Commission to set 20 GW by 2045 as a planning goal. Earlier this year, CEC proposed offshore wind goals of 3 GW by 2030 and 10 to 15 GW by 2045 —targets that some stakeholders called too conservative. (See CEC Postpones Vote on Offshore Wind Goals.)
‘Going Big’ on OSW
Offshore Wind California, a trade group of offshore wind developers and technology companies, is urging the CEC to approve offshore wind planning goals of 5 GW by 2030 and at least 20 GW by 2045. The group said Friday that Newsom’s announcement was “great news.”
“This is another sign California is serious about ‘going big’ on floating offshore wind, to drive economies of scale and realize the very substantial clean power, climate and jobs benefits offshore wind can deliver for our state,” Adam Stern, the group’s executive director, said in a statement.
In another request, Newsom wants CARB to adopt a 20% clean fuels target for the aviation sector.
Newsom also asked CARB to work with the state’s Geologic Energy Management Division (CalGEM) to form a task force to find and fix methane leaks from oil infrastructure near communities.
The governor noted that the state budget allocates $100 million for methane detection satellites plus another $100 million for CalGEM to plug orphan oil wells, which may be leaking methane.
In a new Lessons Learned report posted Wednesday, NERC reminded utilities to be vigilant about the possibility of unauthorized people climbing on their transmission towers.
The Tower Climber Incident report is based on an incident in which a climber ascended to the top of a transmission tower before being detected by the transmission operator (TOP). As is usually the case with Lessons Learned reports, many details of the event — such as its location and the people, utilities and regional entity involved — were omitted to protect potentially sensitive business information. NERC also left out the date of the incident, only stating that it occurred “on an August day.”
Unapproved climbers on transmission towers are an ongoing concern in the U.S., with multiple incidents reported in the last year. In January, Duke Energy had to cut power to more than 15,000 customers after a man climbed an 85-foot tower in Charlotte, N.C., and stayed there for nearly four hours. In addition, The Washington Post reported last August on police in Utah finding hammocks strung high on transmission towers operated by Rocky Mountain Power, though without finding the trespassers themselves.
In the event detailed in NERC’s report, the TOP received a report of a “civilian tower climber” in a 230/500-kV corridor and dispatched a line crew to investigate. The crew was joined at the site by police and emergency services; after receiving confirmation of the report, the TOP relayed it to the reliability coordinator; together with the RC, the TOP decided to remove the three circuits that shared the tower (500 kV, 230 kV and 115 kV) from service to avoid injuring the climber.
To safely shut down the circuits, the RC first ordered import schedules on a nearby interface curtailed to 53% (later 21%) of their value prior to the incident. Internal generation was increased, and all load rejection schemes for the area were armed. The TOP then “reduced the load on the transformers supplied by these circuits” before removing them from service.
Meanwhile, the field crew worked to prepare a clearance so a crane could access the tower. After more than two hours, rescuers were able to bring the climber down, at which point police took the climber into custody. At this point the RC and TOP began to bring the circuits back online, after which the RC rescinded the emergency measures for the area.
Reviewing the incident, NERC noted that climbing a transmission tower poses “a safety hazard to the climber, operational risks to the entity and a potential service loss to consumers.” Its recommendations for TOPs and transmission owners included following policies on the installation of deterrents to prevent climbing; immediately after the event, the TOP had discovered there were “no visible danger/warning signs” in the area, which it addressed immediately.
NERC also suggested that TOs and TOPs ensure they have policies on responding to public safety hazards and communicating with other stakeholders, including first responders in addition to the RC, and that they “establish a minimum above-grade height for tower climbing aids that discourages unauthorized climbing.”
