New Jersey Gov. Phil Murphy on Wednesday outlined a sweeping set of new clean energy initiatives designed to accelerate the state’s goal of reaching net zero, including eliminating power sector emissions and ending the sale of gas-powered cars and light-duty trucks by 2035.
Speaking at Rutgers University in New Brunswick, Murphy set targets to require all electricity sold in the state be “derived from clean sources” by 2035 — 15 years ahead of the current goal — and install electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030. Murphy enshrined both measures in executive orders.
The governor also said he would step up the effort to cut transportation emissions by allocating $70 million in funds from Regional Greenhouse Gas Initiative auctions to reduce the “consumer upfront costs” for medium- and heavy-duty electric trucks.
Murphy added that he would direct the New Jersey Department of Environmental Protection (DEP) to begin the process of securing stakeholder input to implement a version of California’s Advanced Clean Cars II rules in New Jersey. The rules would require all new passenger vehicles sold in the state to be zero-emission vehicles by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
“These bold targets and carefully crafted initiatives signal our unequivocal commitment to swift and concrete climate action today,” Murphy said.” These comprehensive initiatives will better protect and prepare every New Jersey community, including those on the front lines of climate change who have previously been left out and left behind.”
The initiatives also included making 10% of all low-to-moderate income properties electrification-ready by 2030, part of an effort to reduce emissions from the state’s second largest source of greenhouse gases — homes and businesses.
Anticipating the opposition he might face, Murphy said, “No one is going to be forced to do anything,” and added that “No one is coming for anyone’s gas stove.”
“What today is about,” he said, is “giving consumers more choices and more chances to join us in creating a cleaner, more sustainable and more affordable energy future.”
He said his strategy of promoting a shift to electric heating and cooling systems would put “money right back into the pockets of consumers who choose to make the switch.”
Master Plan Concerns
The speech came just under a month after Murphy, who is thought to be preparing to run for president, announced plans to spend more than a year updating the 2019 Energy Master Plan that has underpinned much of the governor’s clean energy efforts, releasing the update in 2024.
In an apparently unrelated move, Sen. Bob Smith (D), who heads the Senate Energy and Environment Committee and shapes much of the state’s clean energy legislation, introduced a bill in January that would establish a sweeping new clean electricity certificate program to cover all energy sources. (See NJ Gov., Lawmakers Move Toward Updated Clean Energy Goals.)
New Jersey has sought to position itself as a clean energy leader, especially with its aggressive plan to build 11 GW of offshore wind power — of which three projects totaling more than 3.75 GW have been approved — and develop a special-purpose offshore wind port to handle the turbine supply chain.
But as the clean energy plans have grown, so have concerns about the cost and impact, with opponents urging the state to focus more on alternative low-emission fuels under development.
After vigorous business and union opposition, the DEP in December backed away from implementing a controversial rule that would have prevented the agency from issuing permits for new fossil fuel-fired boilers in certain situations. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)
And critics of the master plan’s emphasis on shifting to making electricity the state’s main energy source have backed a bill, S2671, that would prohibit any state agency from mandating the use of electric building energy systems until the release of a government report on the costs and benefits of electric heating.
Eric DeGesero, executive vice president of the Fuel Merchants Association of New Jersey, which supports the bill, said he was “gratified to hear Governor Murphy announce that no homeowner or business will be mandated to switch their appliances to electric heat.” DeGesero said 85 % of New Jerseyans heat with natural gas, fuel oil or propane.
“The Murphy Administration and the legislature need to include all energy options on the table, not just electrification,” he said. “Focus should now shift to the most cost-effective way to decarbonize the incumbent fuels to those of the future.”
Preparing for an Electric Future
Murphy acknowledged that his plan “begs the question, ‘What happens to our natural gas utilities as we reduce our reliance on fossil fuels?’”
In response, he issued another executive order Wednesday that directs the state’s Board of Public Utilities (BPU) to “engage with all stakeholders from across the energy industry, organized labor, the environmental spaces, and the Governor’s Clean Buildings Working Group, to take on the big question of the future of the natural gas utility.”
The order said the topics for scrutiny would include:
the “need to ensure reliable operation and long-term financial viability of natural gas public utilities” as their consumer base shrinks;
alternative programs and “investments that could provide natural gas utilities with new revenue streams and promote good-paying jobs;” and
the “elimination of subsidies that encourage unnecessary investment in natural gas infrastructure that is likely to result in stranded costs to customers.”
BPU President Joseph L. Fiordaliso called Murphy’s request for 100% clean energy by 2035 “an incredibly important and sensible policy initiative that solidifies New Jersey as a leader at the forefront of the battle to address the climate crisis.”
The proposal also drew support from two prominent environmental groups, the New Jersey League of Conservation Voters and the New Jersey Sierra Club.
Ed Potosnak, executive director of the state’s League of Conservation Voters, said the organization is “thrilled to see a roadmap to 100% clean electricity, meaningful commitments to electrify buildings, vans, trucks and buses, and updated coastal rules to protect families and businesses — all as we step up efforts to protect our communities from the impacts of climate change.”
WASHINGTON ― The Tennessee Valley Authority has set its sights on 80% carbon-free generation by 2035 and a net-zero system by 2050, with plans to develop a fleet of up to 20 small modular nuclear reactors to meet the utility’s need for increasing amounts of secure, decarbonized electricity, according to CEO Jeff Lyash.
“I have no interest in building one reactor,” Lyash said during a session on nuclear development at the National Association of Regulatory Utility Commissioners (NARUC) Winter Policy Summit on Sunday. “In order for us to be successful, TVA needs something on the order of 20 reactors over that period of time. So, if you can’t see your way to reaching nth-of-a-kind costs, supply chain, workforce, project execution for a portfolio of reactors, I don’t see the point in building one.”
Approved by the TVA board in February 2022, the federally owned utility aims to build its first SMR at its Clinch River location in Tennessee, which now has an early site permit from the Nuclear Regulatory Commission. Separate from a construction permit, this permission provides safety, environmental impact and emergency preparedness approvals for a site where one or more nuclear plants may be built.
TVA will still need a construction permit for the 300-MW GE Hitachi BWRX-300 SMR it is now considering for potential deployment at Clinch River. The utility’s goal is not only to show that the technology works, Lyash said, but that it can be deployed “in a way where you can demonstrate the ability to build enough reactors to materially affect the outcome we’re looking for, which is energy security, decarbonization in the face of electrification and economic growth.”
The rising profile of nuclear power as one of the critical technologies that will power the U.S. to a carbon-free grid was a major theme at the NARUC conference, with Sunday’s session followed on Monday by an on-stage interview with David Wright, a member of the Nuclear Regulatory Commission.
Introducing Wright, who is also a past president of NARUC, Commissioner Tricia Pridemore, chair of the Georgia Public Service Commission, announced the formation of a new Advanced Nuclear State Collaborative, which will bring together members of NARUC and the National Association of State Energy Officials. The Department of Energy is sponsoring the initiative, which will provide technical assistance and expertise for states deploying or considering new nuclear projects, Pridemore said.
The initiative is one answer to the growing interest in nuclear across the country. In at least 20 states, “public service commissions and state energy offices are engaged in feasibility studies for advanced nuclear reactor site selection, strategies to reduce regulatory and policy barriers to new nuclear, and other activities to pave the way for advanced reactors,” she said.
Wright also sees possibilities for the NRC to develop more active relationships with state commissions and policy makers. “There are things [utility commissions] are going to be involved in that need our expertise or maybe even just information,” he told Pridemore.
“There are things you’re going to want to do, and you’re going to want to know — ‘Can I do that?” he said. “Do we have to put certain regulations in place on the state level, or does the legislature have to do certain things?’”
But a bigger question looms for the U.S. nuclear industry and its supporters, including TVA and DOE, which is pouring billions into the development of advanced reactors: Can they adequately de-risk a technology known for massive cost overruns and project delays to build the trust of financial markets and the public at large ― and how fast can they do it?
The Value of Vogtle
The two units nearing completion at the Alvin W. Vogtle Electric Generating Plant near Waynesboro, Ga., are a case in point. Vogtle’s two existing reactors have been operating since the late 1980s, but the plant’s next-generation expansion has become the poster project for cost overruns and delays, with Georgia’s rate payers picking up the tab with higher electric bills to finance construction.
The first new nuclear generation built in the U.S. in 30 years, the project is now six years behind schedule, and its original cost estimate of $14 billion has ballooned to more than $30 billion. Vogtle has also received $12 billion in loan guarantees from the Department of Energy’s Loan Programs Office (LPO), made during both the Obama and Trump administrations.
The first new unit at Vogtle is now expected to come online in May or June, a delay from the previous target of the end of April, Georgia Power said Feb. 16. The second unit is scheduled to begin commercial operation between this November and March 2024. Georgia Power also wrote off $201 million in additional costs for the reactors, reflecting increased costs. Together, the two units will provide 1,250 MW of power.
With completion finally in sight, the industry narrative on the troubled project is focused on its upside and long-term benefits.
Joining Lyash for Sunday’s nuclear discussion, LPO Director Jigar Shah said that Vogtle shows that “America is deciding to do big things. …
“We had to train 13,000 men and women, who were all union, to build those projects, and we now have that trained workforce, and many of those folks paid off debt for their entire families,” Shah said. “I think the transformational nature of what Vogtle did is something that we should celebrate, celebrating the persistence, the spirit of nuclear to get that done.”
That persistence also paid off in Poland’s recent decision to choose the same Westinghouse AP1000 reactors soon to go online at Vogtle for its first nuclear project, Shah said.
Similarly, Lyash sees Vogtle as a first-of-its-kind project that has produced valuable lessons learned. “The key is to have the fortitude and the confidence to harvest those learnings and integrate them and to use [them] to benefit the nation,” he said.
“And those lessons are around project management and execution, risk management, what a supply chain looks like, what the workforce needs to look like,” he said. “Vogtle has helped build the end capabilities now that I’ll be taking advantage of if we move forward with the BWRX-300.”
Despite Vogtle’s problems, Lyash predicted that “a decade from now, you’re going to be very, very happy that you have those facilities. They’re going to be impacting the economy and the environment, and they have generated a design that is beginning to be deployed around the world.”
Shah said, even today, the LPO would provide the same loan guarantees to the project. A key point for such decisions is whether the office sees “a realistic prospect of repayment,” and he expects Vogtle will fully repay its loans.
‘A Fragile System’
The positive momentum for nuclear at NARUC notwithstanding, opinions nationwide about moving forward with new plants remains divided. In its most recent poll on the issue, Gallup found support for nuclear edging up to 51% versus 47% opposed, a slight shift from 2019, when the country was evenly split, 49% to 49%.
A Pew Research poll taken before Russia’s invasion of Ukraine last year found that 35% of those surveyed said the U.S. government should support nuclear; 25% said the government should not support it; while 37% were neutral on the issue.
Opinions also differ on the cost of maintaining the country’s existing 92 nuclear reactors, which provide about 20% of the nation’s power and 50% of its carbon-free electricity.
At the Sunday session, Commissioner John B. Howard of the New York Public Service Commission raised the issue of state subsidies for existing plants, such as New York’s zero-emission credits (ZECs) “that many believe are not affordable and sustainable.”
Nuclear power development has gotten too expensive, Howard said.
A recent NARUC report on the U.S. nuclear market lists New York, Illinois, Connecticut, New Jersey and Ohio as providing ZECs for their existing plants. The Infrastructure Investment and Jobs Act also provides $6 billion in funding for a Civil Nuclear Credit Program to help plants stay open.
But Lyash countered that nuclear plants are “highly competitive.”
According to the NARUC report, more than two-thirds of the clean power supply in 20 states comes from nuclear, and in Mississippi, nuclear accounts for 96% of the state’s carbon-free power.
Nuclear is 42% of TVA’s power supply, Lyash said, and he expects that percentage to hold steady even as the utility’s electricity demand increases with economic growth and electrification of buildings and transportation.
Nuclear plants are “high capital on the front end, but they have a tremendously long and beneficial life,” he said. “They also deliver all the attributes to a power system that you need — voltage, frequency, maneuverability.”
Echoing a familiar nuclear industry argument, Lyash said ZECs should not be seen as subsidies, but rather as paying nuclear plants “for the value that they already delivered because markets have a difficult time recognizing that.”
Shah framed the case for nuclear in terms of system reliability. “We have a fragile system, and that fragility has come from [independent power producer]-run natural gas plants,” he said. “For the last three years, we have seen a historic amount of failure out of those gas plants. … For many people, nuclear power represents a better form of baseload clean power to be able to provide that to people long term, [but] what they are afraid of is that we haven’t figured out how to build them on time, on budget.”
TVA’s Clinch River project could be the next step toward that goal, he said.
Lyash countered that the issue was not system fragility, per se, but the rising expectations of customers who are themselves increasingly dependent on electricity. “If you roll back 75 years, only about 2% of all the end-use energy in this country came from electricity; today it is 22%, and by 2050, it’s probably going to be 50%,” he said.
“The level of reliability on the U.S. electric system hasn’t generally degraded,” Lyash said. “The customer expectations have risen, and not just day-in, day-out reliability … but resiliency — how does it perform when it’s [confronted] with the thing you hoped would never happen or happens infrequently,” such as December’s Winter Storm Elliott.
“People’s expectations are entirely different. … Twenty years ago if your lights went out for 20 minutes, or flickered, you would not have cared,” he said. “Today you really care about this.”
‘No Shortcuts’
Lyash also sees SMRs, like the BWRX-300, as easier to integrate on the grid. Smaller reactors could be strategically sited to ease transmission congestion, and in the event of an emergency, taking 300 MW offline would be less disruptive to system reliability than bigger units, he said.
Lyash, Shah and Wright are expecting nuclear development in the coming years to be centered on or near closed coal-fired plants with existing transmission, circumventing the need for extensive new transmission construction.
Shah pointed to a recent DOE study that identified 157 closed coal plants and an additional 237 coal plants still in operation as potential sites for coal-to-nuclear transition. The study also found 80% of those sites well suited for the development of advanced reactors of less than 1 GW.
For example, TerraPower’s 345-MW Natrium reactor, one of two projects being developed under DOE’s Advanced Reactor Demonstration Program, is being planned for Kemmerer, Wyo., where a PacifiCorp coal-fired plant is scheduled for retirement in 2025. The DOE program has $2.5 billion in funding from the Infrastructure Investment and Jobs Act and is supporting the development of two advanced reactors that are scheduled to be online by 2027.
The second reactor, X-energy’s Xe-100, is being planned for a site in Washington state near an existing nuclear plant.
Wright sees these demonstrations and other coal-to-nuclear projects as the “low-hanging fruit” of the next wave of nuclear development. Siting a nuclear project on or near a closed or existing coal or nuclear plant could streamline permitting because “they’ve already got an [environmental impact statement],” he said. “We don’t want to have to do an [analysis] if they’re going on a site that’s already been done. …
“There may be some tweaking to some regulations and rules we have to do in order to get ready, but we don’t want to be the reason that they delay [or] they don’t even get to market,” he said.
NRC is also staffing up in preparation for what it expects to be an increasing number of projects applying for approval, Wright said. “We’re onboarding 400 this year,” he said.
While planning for an aggressive nuclear buildout, Lyash said TVA wants to pursue a diversified portfolio of clean energy resources that balances energy security, affordability and decarbonization. “No one resource can satisfy” these goals, he said. “You have to think about this not as a choice between wind or solar or nuclear or hydro or storage. It’s the combination of all the right technologies in a portfolio that delivers energy security and [clean] energy to drive the economy.”
Shah agreed, saying all resources should be on the table. The enthusiasm for nuclear at NARUC is part of the growing interest in other technologies, such as enhanced geothermal and low-impact hydropower, he said. Going forward, he sees industry enthusiasm and support for “all of the tools that have reached the level of maturity so they can rise to the occasion” of decarbonizing the U.S. economy.
But Shah said the greatest challenge ahead for nuclear may be building trust. “I think the nuclear industry, for better or for worse, was dormant for the better part of 30 years, not really pursuing innovation for the better part of 30 years,” he said. Now the industry is developing SMRs and other innovative advanced reactors, but “they have to do a proper job. They have to learn all the lessons. They’ve got to make sure they measure 34 times and cut once.
“There’s no shortcut to building trust,” Shah said. “It’s about doing these things in a highly competent fashion, making sure there is transparency, that we’re fully admitting all the mistakes that were made in the past and learning from them.”
Physical attacks on electric infrastructure have been the upswing over the past year, with recent attacks in North Carolina and Washington state and a foiled plot in Baltimore bringing more attention to the issue, experts said at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit on Sunday.
“Over the last year, we’ve seen a marked increase in security incidents,” NERC Senior Vice President and Electricity Information Sharing & Analysis Center (E-ISAC) CEO Manny Cancel. “So the bad news is that there has been an increase — a fairly significant one compared to the baseline of the previous five years.”
While attacks are on the rise, only a small portion of physical attacks actually cause any damage to the broader power grid, Cancel said. But those that do can have major impacts, such as in North Carolina late last year. (See Duke: NC Outages from Attacks May Last Until Thursday.)
Physical attacks have been clustered close together geographically, sometimes with multiple assets in the same area targeted, and sometimes the same infrastructure has been hit more than once, said Cancel.
While a handful of suspects have been arrested, in most cases the industry is not aware of who is attacking its infrastructure, Cancel said. Some of the cases are clearly just petty theft with infrastructure being stripped of copper or other valuables.
FERC and NERC have set up mandatory Critical Infrastructure Protection (CIP) standards that deal with both cyber and physical attacks. Those standards helped to minimize the impact of the North Carolina attack in December, Cancel said, but NERC is also working on expanding those to better protect the grid.
Reliability standards today are focused on protecting against grid instability and preventing cascading outages, but going forward, Cancel said, it might make sense to update standards to minimize the loss of load from attacks and to better protect against coordinated efforts such as the foiled plot in Baltimore, where neo-Nazi extremists planned to attack multiple assets. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)
While physical attacks on the grid have made more headlines recently, the E-ISAC and NERC spend just as much time on cybersecurity, which can prove riskier to the grid.
“Certainly, cyber has the capability to do more at scale,” Cancel said. “And certainly when you factor in the capabilities of nation-state adversaries, those are very complex adversaries that have really strong potential … to carry out attacks.”
The recent spate of attacks has the industry on the verge of a paradigm shift, said Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security.
“If you remember, prior to 9/11, the airport security … was effective for the cost that we paid,” he said. “After 9/11, there was a paradigm shift. And so you know, we paid a lot more [for] a lot more security and a lot bigger hassle associated with that security, but it was worth worth the cost.”
Historically, the main security worry for the industry was a random person wandering into a facility and getting hurt, which could be taken care of with fences, McClelland said. But now the industry needs to step up its game by analyzing risks around the grid and coming up with a cost-effective plan to make it more effective.
CIP standards are foundational practices to ensure a minimum level of security, while McClelland’s group at FERC is focused on best practices.
“We’re looking for those advanced adversaries that specifically target our energy infrastructure,” McClelland said. “Using this two-pronged approach, FERC can move very quickly, even against the most advanced aggressor.”
The commission works closely with other governmental agencies to determine who is trying to attack the grid, which can help it come up with best practices for defense. FERC staff can then bring some of that information down the industry, even granting state commissioners one day of security clearance so they can be briefed on any relevant threats.
“We will read in, so to speak, those state commissioners, and in that session, we’ll do a classified briefing,” he added. “But as importantly, perhaps more importantly, we do a working session where we talk specifically about how these adversaries can be stopped.”
As threats emerge in between those briefings, FERC will also issue advisories so that any new major issues are known by those under threat.
“If there are utilities that are particularly targeted, or the networks and systems that they operate have shown some vulnerabilities and showing some attention from adversaries, we will contact those utilities and we will work specifically with them to help them understand the threats and then work with them to also assess how vulnerable they are to the threats,” McClelland said.
Another way of informing the industry is through a regular tabletop exercise called “Cyber Yankee” that FERC holds with the industry in which they simulate grid attacks based on real threats, McClelland said.
The SouthCoast Wind project could have significant impacts on marine mammals, fisheries and navigation off the Massachusetts coast, according to a draft environmental impact statement.
The U.S. Bureau of Ocean Energy Management on Monday announced the release of the draft EIS for SouthCoast Wind, formerly known as Mayflower Wind, about 20 miles south of the island of Nantucket.
The 127,388-acre lease area has a generation capacity of up to 2,400 MW. SouthCoast Wind Energy, a joint venture of Shell New Energies US (NYSE:SHEL) and Ocean Winds North America (EDP Renewables and ENGIE), announced its new name Feb. 1.
SouthCoast plans to establish grid connections in Massachusetts for the first 1,200 MW, though the company has indicated the terms it negotiated for sale of 400 MW of that electricity have become uneconomical. (See Financial Concerns Continue for Major Northeast OSW Projects.)
With its appendices, the BOEM report totals 1,927 pages. It examines the potential impacts of the project as proposed and of four modified versions, as well as the anticipated result of the status quo if the project were never constructed.
Most of the findings are presented as a range of possibilities, and most of the alternatives resulted in little change in the projections.
Air quality, for example, could see minor adverse impacts from the emissions associated with construction and minor beneficial impacts from less fossil fuel being burned to generate electricity, once the offshore wind turbines come online.
Habitat disturbance could have a negligible to moderate negative impact on marine life forms, but the new underwater hard surfaces could create new habitat, and therefore have a moderate beneficial impact.
Some birds would be killed by spinning turbine blades, others would see their shoreline habitats disturbed, and still others would gain increased foraging opportunities; together, the report rates these as both a minor negative and minor beneficial impact.
Underwater noise and increased risk of collisions with vessels would affect whales and other marine mammals to an unknown degree; the report rates the negative impact as anywhere from negligible to major.
The commercial fisheries would suffer a minor to major impact, depending on the type of fishery; most vessels could adapt their operations to adjust but others would experience significant and lasting disruptions. The cumulative fisheries impact of this and other wind energy projects proposed off the Northeast U.S. coast is rated as major.
The report says the commercial species most affected in the offshore project area is longfin squid. Atlantic surfclam and ocean quahog fisheries told BOEM their operations require a minimum distance of 2 nautical miles (3.7 kilometers) between turbines for safe operations. The report said problems could also arise if mobile species such as Atlantic herring, Atlantic mackerel, squid, tuna and groundfish, are attracted to the wind farm area.
SouthCoast plans up to 147 wind turbine generators standing up to 1,066 feet tall, spaced 1 nautical mile apart in a uniform north-south/east-west layout.
Although state officials have embraced offshore wind as a source of economic development, BOEM projects minor employment and economic impacts from the project, with negative impacts on fishing and recreational pursuits and positive impacts on job creation and tax revenue.
Little net impact is seen on environmental justice, except in the case of tribal nations, because of the potential major impacts on submerged ancient landforms.
Vessel traffic might be impacted by the wind farm, perhaps even to a moderate degree, because of revised navigation routes, port delays and degraded radio and radar signals. A moderate negative impact is foreseen on search and rescue operations, and a major impact is expected on scientific research and surveys.
BOEM, which will publish the draft report Friday in the Federal Register, will accept public comment through April 3. It has scheduled three virtual public information sessions in late March.
Siemens Gamesa said Monday it will build an offshore wind turbine nacelle factory in upstate New York if its turbines are selected for the next group of wind farms to be built off the state’s coast.
The factory would sit along the Hudson River near other factories that are proposed as part of the offshore wind supply chain officials are trying to create within New York.
The project would generate roughly $500 million in local investment, the company said, and create about 420 direct jobs. The company said it would seek to source component supplies locally, sparking indirect employment growth at other companies.
Siemens Gamesa said in a news release that the proposed factory and the accompanying supplier network also would support the company’s activities elsewhere on the East Coast, where multiple offshore wind farms are in various stages from concept to construction from Maine to South Carolina.
New York alone wants to have 9 GW of offshore wind online by 2035.
“The announcement of this proposed facility in New York is a major step forward in our desire to lead the massive U.S. offshore wind market,” Marc Becker, CEO of Siemens Gamesa’s offshore business, said in the news release. “We’re excited by the opportunity presented by the State of New York to further develop our manufacturing footprint.”
In its third offshore wind solicitation, which closed Jan. 26, New York required developers to submit supply chain investment and workforce development plans with their wind farm proposals.
But given the limited availability and high cost of waterfront real estate in and near New York City, much of that supply chain will be inland.
Siemens Gamesa’s factory would be in Coeymans, which is 130 miles from the Atlantic Ocean but reachable by ocean-going vessels.
That stretch of the Hudson River could become something of a hot spot for the offshore wind industry.
Ørsted and Eversource Energy (NYSE:ES) already have contracted with Riggs Distler to build foundation components for their Sunrise Wind project at the Port of Coeymans, creating an estimated 230 jobs.
Eight miles north, in the Port of Albany, a facility employing up to 350 people to make turbine towers and transition pieces is planned by a partnership that includes Equinor.
And General Electric (NYSE:GE) announced last month that if there were enough orders for projects in New York waters, it would build two factories in Coeymans: one for offshore wind turbine blades; one for turbine nacelles. GE said the two would create approximately 870 direct jobs and support roughly 1,400 indirect jobs.
There would be a bit of irony in Siemens Gamesa and GE setting up nacelle factories close to one another: On Feb. 2, a federal judge ruling in a patent infringement case ordered GE to pay Siemens Gamesa $60,000/MW for all GE Haliade-X wind turbines installed at the 1,100-MW Ocean Wind 1 project off New Jersey.
When it announced its potential plans in Coeymans, GE said the components made there would be used in the next generation of the Haliade-X.
The New York State Energy Research and Development Authority said in late January that the state’s latest offshore wind solicitation drew record interest with six developers proposing eight projects. (See: NYSERDA: 3rd OSW Solicitation Breaks Record.)
Tesla has been gobbling up state-backed economic development incentives in Nevada, including the entire Northern Nevada allocation for an electric rate rider program.
Under the Economic Development Electric Rate Rider program, NV Energy had 50 MW to allocate, according to a report to the Nevada legislature from the Public Utilities Commission of Nevada. The 50 MW was split evenly between the utility’s northern and southern Nevada territories.
In northern Nevada, the entire 25 MW went to Tesla, whose 5.4 million square-foot gigafactory is near Reno. In southern Nevada, 1 MW was allocated through the program to Xtreme Manufacturing, which makes heavy equipment for construction.
A business accepted for the rate rider program receives a discount off the base tariff energy rate portion of its electric bill. Discounts provided through the program totaled $9.45 million as of the date of the PUCN report.
The PUCN voted 3-0 on Monday to approve the report.
Gigafactory Incentives
The rate rider is just one economic development incentive that the state of Nevada has granted to Tesla. Since 2015, Tesla (NASDAQ:TSLA) has received $410 million in tax abatements in Nevada related to the Nevada gigafactory, according to an October report from the Governor’s Office of Economic Development (GOED).
The tax breaks were for real and personal property tax, modified business tax, and sales tax on construction equipment and materials. The abatements last for 10 to 20 years.
In addition, Tesla received $195 million in transferable tax credits.
The tax abatements and credits were allowed through Senate Bill 1 from the legislature’s September 2014 special session. The bill authorized tax breaks for projects with a capital investment of at least $3.5 billion within 10 years.
Tesla is the only company that has qualified for tax abatements under the legislation, the Nevada Current reported.
Tesla said it has invested $6.2 billion in Nevada since 2014.
More tax incentives for Tesla may be on the way.
The electric vehicle manufacturer announced last month plans for a $3.6 billion investment in Gigafactory Nevada, including a new battery factory and its first high-volume manufacturing facility for electric semi-trucks. (See Tesla to Invest $3.6B in Nev. Truck, Battery Factories.)
The GOED is scheduled to discuss potential tax breaks for Tesla’s new investment on March 2; it will release details of the proposal later this month.
Rate Rider Revived
Nevada’s Economic Development Electric Rate Rider program expired in 2017. But the state legislature revived the program in 2021 through Senate Bill 448. It now runs through 2024.
A business accepted for the program receives an electric rate discount of up to 30% in the third and fourth year of the contract; up to 20% in years five through eight; and up to 10% in years nine and 10. There’s no discount in the first two years.
In addition to Tesla and Xtreme Manufacturing, GOED approved two other businesses for the electric rate rider. Those approvals hadn’t yet been filed with PUCN.
In March, the GOED board approved a 5 MW allocation for Haas Automation for its planned factory in Clark County. Another 5 MW allocation was approved in June for Ball Metal Beverage Container Corp. for a Clark County factory.
Electric trucks already on the market could replace 20% of the diesels taking cargo in and out of the Port of New York and New Jersey, but full electrification would require vehicles with larger batteries and greater range, according to a new report by the National Renewable Energy Laboratory (NREL).
The report tracked 46 trucks serving the port on trips totaling 121,000 miles over eight weeks and concluded that the routes executed by nine of the trucks could be done with an existing battery of about 375 kWh, with recharging taking place every time there is a two-hour break during the day.
The nine routes could be performed by existing electric trucks because they cover shorter distances. The average route across all the trucks was 140 miles, and the longest route was 573 miles. Those longer routes meant that a substantially larger battery — between 900 kWh and 1,600 kWh — would be needed for electric trucks to cover the remaining routes, the report states.
A battery at the lower end of that range could be used if there were more charging breaks during the day and faster chargers, the report said. But it added that “specific days of operation would require over 1,600 kWh of energy due to longer distances and more intense operation, which is not currently possibly without operational changes,” the report concluded. It added that full adoption of EV trucks would cut carbon emissions from the trucks by 75%.
Port fleet operators say there are relatively few electric truck models available. That is changing, however. Freightliner put its eCascadia (up to 438 kWh and up to 230 miles in range) into production last May. In December, Tesla began delivering its Tesla Semi (up to 500 miles on a single charge) to buyers. (See Tesla to Invest $3.6B in Nev. Truck, Battery Factories.) Both are Class 8 vehicles (over 33,000 pounds, including 18-wheelers).
NREL’s 47-page report also concluded that electric trucks “could be cost-competitive on an energy-cost-per-mile basis for all scenarios while diesel is above $3.00/gal.” The current price for diesel in the state is $4.90/gallon, according to Globalpetrolprices.com.
The report is one of two new studies that focus on the viability of electrifying different elements of the port activity and assessing the impact on emissions in the port, most of which is located in New Jersey and is the largest on the East Coast.
The reports offer a glimpse of what can be achieved through electrification, but also the extensive challenges standing in the way of widespread EV truck adoption, especially from the still limited truck technology available.
Trucks 25% of Transportation Emissions in NJ
New Jersey says electric trucks are key to reducing carbon emissions and pollution because trucks account for 25% of emissions from transportation, the state’s largest source of emissions. The state’s Energy Master Plan, released in 2019, assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050. The Port Authority of New York and New Jersey, which runs the ports, has set a goal of reaching zero emissions by 2050.
The workload for drayage trucks — those that pick up and deliver goods to and from the port — varies a lot from truck to truck. Some do short trips to and from a warehouse or distribution center a few miles from the port while others do round trips of several hundred miles into Pennsylvania or the outer reaches of New York state.
So far, however, only a few electric trucks work in the port, and most of those are yard tractors that move containers short trips within the port’s perimeter. Truckers say electric vehicles are too expensive; the range is too limited; and there aren’t enough charging stations to rely on for recharging.
Red Hook Container Terminals in August 2021 introduced 10 electric yard tractors. (See Port of NY-NJ Unveils Fleet of 10 EV Trucks.) Earlier in the year, International Motor Freight outlined a plan to put 16 electric trucks, bought with $5.9 million from the state Volkswagen settlement, into service. (See NJ Looks to Boost Heavy-duty Charge Points.)
Many port trucking operations are run by small independent operators who have only a few trucks and lack resources to invest in EVs or charging stations, according to port officials. (See Port NY-NJ Cites ‘Hurdles’ to Employing EV Trucks.)
The second report, a working paper released on Feb. 6 by the International Council on Clean Transportation, documents case studies of the ports of New York and New Jersey and Seattle and concludes that electrification at both could lead to dramatic cuts in emissions.
The report found that drayage trucks generate about 23.5% of the carbon in the port of New York and New Jersey, and oceangoing vessels bringing the goods in and out of the port generate about 52%. The remaining 25% is generated by harbor craft, such as ferries and tugboats.
The ports could cut emissions from ocean vessels by half if they provided electricity to power them while they are sitting in the port, rather than them running their engines, the report says.
Subsidies
In New Jersey, state agencies have embarked on several initiatives to promote the purchase of EV trucks and stimulate the development of EV charging stations. The New Jersey Economic Development Authority expects to begin accepting applications within weeks for subsidies toward the purchase of the largest trucks, offering $135,000 for a Class 7 truck (ranging between 26,001 and 33,000 pounds, such as garbage collection vehicles or livestock transports) and $175,000 for a Class 8 truck. (See Electric MHD Truck Incentives Promoted in NJ.)
The program has so far provided financial support for the purchase of 370 trucks, but that is a tiny sliver of the 500,000 trucks that the New Jersey Board of Public Utilities says drive in the state.
The NREL report demonstrates the interplay between battery size, the availability of chargers and the size and charging speed of the chargers. For example, one of the fleets studied would need a 1,600-kWh battery on each vehicle to cover all its routes if charging could take place at a 175-kWh charge rate when there was a break of at least two hours. But the battery could drop to 900 kWh if the charge rate was 300 kWh and charging could take place every time the truck stopped for 10 minutes.
If a truck could be charging every time it stopped for ten minutes, the number of routes that could be done with today’s battery size would increase from nine to 24 the report said, adding that such a scenario is not feasible today with current charging technology and infrastructure.
A key issue for drayage trucks is the location of where the truck takes a break, and whether there is a charging station there. For instance, some of the trucks’ stop time — known as dwell time — is in the terminals, where charging would not be possible, the report said.
The report added that ports are in some ways ripe for truck electrification because about 9% of the trucks’ energy is spent idling, either waiting to enter the terminal or to pick up or deliver a container or products, or other tasks, the report says.
EV trucks “use very little, if any, energy when they are stopped,” the report says. “In contrast, conventional internal combustion engine trucks may use a significant amount of fuel and generate emissions while the engine is idling.”
Moreover, “there may be potential for opportunity charging during times when the truck would traditionally be idling,” providing there is charging infrastructure available at the places where the trucks idle, the report added.
MISO told stakeholders Monday that as much as 23 GW of natural gas-fired generation was unavailable during the December winter storm, accounting for almost half of the grid operator’s forced outages.
Staff said during an Entergy Regional State Committee meeting that forced outages reached 50 GW during the last two days of the Dec. 22-24 storm, up from 30 GW during the first day. Natural gas generation outages comprised 23 GW on Dec. 23 and 22 GW on Dec. 24, up from the 9 GW on Dec. 22. Forced coal-resource outages varied between 13 and 16 GW during the storm.
The MISO footprint’s demand hit a likely winter peak of 107 GW on Dec. 23. Demand in MISO South peaked at 32 GW on Dec. 23, nearly matching the South’s record of 32.9 GW set last June.
Staff said gas supply availability issues ultimately tipped the system into emergency procedures on Dec. 23 as they tried to maintain exports to neighboring regions. The maximum-generation emergency lasted for three and a half hours, forcing MISO to call up 1.2 GW of load modifying resources.
MISO’s director of operations risk management, Jason Howard, told the ERSC that pipeline issues and fuel availability, not insufficient weatherization measures, contributed to the unplanned outages. He said staff are working to quantify operations data to better anticipate future winter storms.
In a blog post, Paul Arbaje, an energy analyst with the Union of Concerned Scientists, called the level of outages “troubling” and “equivalent to more than a third of the capacity that should have been available.”
MISO’s operations team drew parallels between this storm and the February 2021 severe-weather event. Howard said although the storm arrived earlier than staff predicted, the severe weather played out as expected. Staff said “abnormally high load forecasting errors” occurred because of a lack of historical data for “similar extreme conditions in December.”
Howard said the storm’s impact over most of the continental U.S. caused MISO and the industry to “really struggle” in gauging demand.
The grid operator’s exports pushed electricity served to 111 GW on Dec. 23. “MISO consistently exported power to southern neighbors with a maximum value of nearly 5 GW,” Howard said. (See MISO Actions During December Storm Spark Debate.)
The RTO said it honored a request to tamp down flows by 1,500 MW across its Midwest-to-South transfer constraint during the Dec. 23 morning peak, which produced emergency conditions in MISO South and a recall of non-firm exports. MISO can normally flow 3,000 MW south and 2,500 MW north across the transmission constraint, part of an agreement with its neighbors.
Scott Wright, executive director of resource adequacy, said because it’s becoming more unpredictable to respond to system operations, MISO has expanded Resource Adequacy Subcommittee meetings into two-day affairs. Staff will use that time to define essential resource attributes, create a new accreditation process for non-thermal generation and design a sloped demand curve for the capacity auction.
“We’re exploring with a conviction that we can do something,” Wright said.
American Electric Power and Algonquin Power & Utilities subsidiary Liberty Utilities have filed a fresh application with FERC seeking approval of AEP’s Kentucky operations’ sale to Liberty.
This time, the two utilities have added new commitments so the sale won’t raise customer rates (EC23-56).
FERC shot down the sale in December, indicating more consumer protections were needed before the commission could give its blessing.
The utilities have since added more safeguards, including a five-year freeze on the current return on equity and 55% equity capital structure; a commitment from Liberty to maintain the same credit profile for five years; and a five-year cap on operations and maintenance and administrative costs at the 2022 rate.
AEP and Liberty also pledge to hold wholesale power and transmission customers harmless from any transaction costs for five years following the sale. The proposed transaction’s other aspects remain unchanged.
The utilities are requesting an expedited review of the application and hope to the close the transaction by April 26. If they fail again to gain commission approval by then, termination rights kick in for the parties.
“When taken in total, these commitments will ensure that the transaction has no adverse effect on both Kentucky Power or Kentucky TransCo’s individual rates and the rate for the AEP East zone,” AEP and Liberty said in the filing.
The new sale application continues AEP’s two-year effort to offload its Kentucky operations to Liberty. Late last year, the parties agreed to shave $200 million off the purchase price down to $2.646 billion. (See AEP Accepts Lower Price for Kentucky Operations Sale.)
AEP said the transaction’s approval should bring an economic boost to retail customers in an “economically disadvantaged part of eastern Kentucky.” It cited previously agreed-upon compromises at the Kentucky Public Service that include a $40 million fund to help offset volatile fuel rates for the remainder of the year; a $55 million, three-year rate holiday on collecting a Big Sandy nuclear plant decommissioning rider; a $43.6 million cut in regulatory charges collected from customers for storm costs; and a new Kentucky call center in the Kentucky territory.
“AEP and Liberty are committed to the sale and are requesting FERC’s accelerated review of the application so customers in eastern Kentucky can begin benefiting from the transaction,” AEP CEO Julie Sloat said in a statement.
Sloat said the sale is just one component of AEP’s strategic plan. She said utility leadership remains dedicated to selling AEP’s competitive renewables portfolio and conducting a review of its retail business as part of its equity financing plan and goal for a 6 to 7% long-term growth rate.
WASHINGTON — Despite making progress after repeated high-profile winter reliability events, the gas and electric industries still have more work to do to coordinate their operations enough to avoid such incidents in the future, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit Monday.
Winter Storm Uri in February 2021 and Winter Storm Elliot in December 2022 each presented the power and gas sectors with a different set of problems, according to MISO President and COO Clair Moeller.
But Moeller said the events shared a common thread: Those problems were rooted in a continued disconnect between the industries — one stemming from difference in how they operate.
“Electricity is ‘N minus one’ forever,” he said, referring to the power industry’s “N-1” reliability criterion, which holds that the grid must be equipped in a way that it can lose a major resource or transmission line without threatening electricity supply. “Gas is like, ‘You know, pipes don’t fail very often, so maybe it’s not worth those investments.’”
The gas industry has been more focused on the commodity itself rather than ensuring resilient operations because nobody has paid it to provide the latter, he said.
“Just to make it more fun in the planning horizon, we’re asking them to become intermittent resources, the reciprocal of renewables, to fill all those holes, and at the same time, we’re electrifying, taking their base load,” Moeller said. “So, the planning problem here is enormous.”
The differing business models makes it difficult to figure out whom to talk to in order to bridge the differences between the two industries, Moeller said. And even within the gas industry, the pipelines have their own issues, which are different from the local delivery companies and natural gas suppliers.
“There really isn’t a very good place to talk about it except here, which is why I bring it up,” Moeller said. “It’s time; the penetration of renewables is accelerating. We’re relying on gas to be that reciprocal intermittency. But we haven’t told them what that looks like, and we haven’t shown up with a checkbook to make sure that they can do it.”
After experiencing the polar vortex of 2014 and helping its neighbors get through Uri, PJM Senior Vice President of Operations Michael Bryson said he thought his RTO had achieved good coordination with the gas industry.
“I think we found out during Elliot that there were certainly gaps in what we were able to see in terms of availability,” Bryson said.
PJM’s load forecast was off by about 10% as it was not ready for the rapid temperature drop over the Christmas holiday weekend, but it also ran into plenty of outages of gas-fired plants that its operators were unaware of until they tried to dispatch the units, he added.
“We actually had, in fact, during Elliot, what I would consider the golden ticket of capacity performance gas: firm transportation, firm supply, no notice scheduling,” Bryson said. “We had units with that, that were curtailed.”
PJM does not have visibility into the operational issues natural gas suppliers might be running into during extreme weather, and that could be fixed by requiring similar information sharing between the gas and electric industries as the RTO does with its neighboring grid operators, he said.
Post-Uri Reforms in ERCOT
Texas has been working on reforms to its power market since Uri knocked out about 50,000 MW of its generation, plunging the state into blackouts that lasted for five days and causing hundreds of deaths and billions of dollars in damages. They include mandatory winterization standards that can be enforced with fines of $1 million per violation per day, said Public Utility Commission of Texas Commissioner Lori Cobos.
“We’ve also developed a first-in-class, first-in-the-country new firm fuel product to help ensure winter resiliency when fuel availability issues arise,” Cobos added.
The PUC authorized ERCOT to procure up to 3,000 MW for the new firm fuel product, and it signed up 19 power plants, 18 of which can burn fuel oil with storage onsite, while the other has a direct pipeline connection to its own natural gas storage facility. All the generators can provide power for up to 48 hours.
ERCOT used the firm fuel product for the first time during Winter Storm Elliot just before Christmas, calling up eight generators that supplied 950 MW, Cobos said.
While the product provided some guaranteed generation, the PUC still is looking into the 13,000 MW of generation that went offline during Elliot, specifically whether any had weatherization issues, she said.
Gas-fired generation has grown at the expense of coal because it is cleaner, but it cannot be stored. And now the electric industry is relying on the gas industry to meet needs the gas system was never designed for, said Chris Moser, head of competitive markets and policy at NRG Energy (NYSE:NRG).
“The gas system itself is well-built; the electric system itself is well-built. The combination of those two systems, frankly, is brittle,” Moser said. “And it’s the touchpoints in between the two of them, some of them just on a daily basis, where things start to break down.”
The issues are exacerbated during winter storms, when spot prices for natural gas spike to above $100/MMBtu, which leads to generator bids above the price cap in many markets. Uri saw prices reach $1,200/MMBtu on the border of Texas and Oklahoma despite the region’s vast supplies of natural gas, said Moser.
When gas is just $4 or even $10/MMBtu, generators can deal with it, but once prices get into the hundreds that can “sink an entire company,” Moser said.
