Exelon announced a leadership transition on Wednesday and reported “solid” third-quarter financials on Thursday.
Current President and COO Calvin Butler Jr. will succeed Chris Crane when he steps down Dec. 30 as CEO and director of the board of the Chicago-based utility.
Crane, who has been Exelon’s CEO since 2012, said he had to accelerate his retirement plans because of significant health issues.
Butler has held a series of leadership roles since joining the company in 2008. He was named executive vice president and chief operating officer in February 2022 and was promoted to his current roles just two weeks ago.
Crane presided over his final quarterly earnings call Thursday, updating industry analysts on the company’s outlook and performance, which he described as “solid.”
For the third quarter of 2022, the company reported GAAP net income of $0.68 per diluted share and adjusted (non-GAAP) operating earnings of $0.75, up from $0.47 and $0.53, respectively, in the same quarter in 2021. For the first nine months of this year, Exelon reported $1.65/share, up from $1.33 in the same period of last year.
The company narrowed its guidance for the full 12 months of 2022 to $2.21-$2.29 in adjusted (non-GAAP) operating earnings per share.
Like the rest of the Nasdaq Composite, Exelon’s stock (NASDAQ:EXC) is near a 52-week low. The share price was down 2.84% in heavier-than-average trading on Thursday as the Nasdaq Composite declined 1.73%.
During Thursday’s conference call, Crane addressed the monumental transition to clean energy underway in the electric utility industry.
Exelon, he said, is well-positioned to lead and benefit from the shift.
“Exelon offers an unparalleled exposure to that opportunity,” Crane said. “We serve more electric and gas customers than any other utility in the country in some of the largest cities of the country. We have earned the trust of our customers and our commissions by consistently reliably providing top-notch operation performance.
“And we live our values with steady commitments to our path-to-clean goal as well as through environmental advocacy and support for our communities in a strong governance model. As a result, there is a tremendous demand and support for investments we expect to make in our communities, which, as I said earlier, totals $29 billion of capital from 2022 to 2025.”
‘Privilege and Responsibility’
Crane has spent his entire career in the energy industry, joining ComEd in 1998, shortly before it became part of Exelon.
He was named Exelon’s chief nuclear officer in 2004 and took over leadership of its fossil, hydro and renewables facilities in 2007.
Crane was named president in 2008 and CEO in 2012. Under his leadership, Exelon merged with Constellation Energy and Pepco Holdings in 2012 and 2016 to become the largest U.S. energy company by customer count.
Also on his watch, ComEd became embroiled in a multiyear bribery scandal at the Illinois Capitol, allegedly forking over $61 million in return for legislation that boosted its profits and bailed out its money-losing nuclear plants. A federal investigation ultimately led to the indictment of several former Exelon executives and a $200 million fine for the company in 2020.
Crane’s successor has three decades of experience in the utilities industry and in regulatory, legislative and public affairs.
Early in his career, Butler worked in government affairs at Central Illinois Light Company. He later had senior leadership roles with R.R. Donnelley, a print, digital and supply chain company. He joined Exelon in 2008 and held various leadership roles at ComEd and Baltimore Gas and Electric before becoming BGE’s CEO in 2014.
He holds a bachelor’s degree from Bradley University, a juris doctor degree from Washington University School of Law and an honorary doctorate of humane letters from Morgan State University.
“Leading Exelon is a privilege and responsibility that I take very seriously,” Butler said in a news release. “Chris is a tremendous leader, mentor and friend. As our world has been undergoing significant change, so too has the energy industry, and Chris has been at the forefront of that evolution. At Exelon, we are uniquely positioned to lead the nation and our industry to a clean energy future that is safe, reliable, affordable and equitable for all. I appreciate the Board’s confidence in me and will do everything I can to serve our customers and communities, keep our employees safe and move the energy industry forward.”
In a new report released this week, NERC warned that the bulk power system is in the middle of a major transformation because of the spread of distributed energy resources, creating a learning curve for which stakeholders are in danger of falling behind.
In the Distributed Energy Resource Strategy document published Tuesday, NERC said the ongoing “influx of DERs presents potential benefits as well as challenges for grid reliability, resilience and flexibility,” noting that the cumulative capacity of distributed solar facilities is set to rise from about 25,000 MW last year to more than 60,000 MW by 2031. The organization said its goal in presenting the report is to outline “current and future strategic actions” to ensure the grid can be operated reliably as these resources’ share of generation grows.
The new report is similar to a document NERC produced in September, detailing the organization’s risk mitigation strategy for inverter-based resources, a class of generators that includes large solar and wind farms. (See NERC Outlines IBR Risk Mitigation Strategy.)
NERC’s System Planning Impacts from DERs (SPIDER) Working Group has played a major role in the ERO Enterprise’s efforts to adapt the grid for the impact of DERs. The group defines DERs as “any source of electric power located on the distribution system,” which refers to electrical facilities located behind a transmission-distribution transformer that serve multiple end-use customers. In practice, this most often refers to rooftop solar panels and storage technology at businesses or homes.
DERs are attractive for end users because they offer the opportunity to reduce electric bills and provide some chance of operating independently in the event of a service outage; they can also lighten the burden on utilities during periods of high demand, decreasing the risk that interventions like load shedding will be needed. In a report issued in August, SPIDER noted that because they sit behind the meter, DERs have traditionally been viewed as a part of the distribution system only, with little or no impact on the broader bulk power system. (See NERC’s SPIDER Group Warns of Modeling Difficulties for DERs.)
However, the new report warned that the installation of these resources on the grid has proceeded much faster than BPS planners’ understanding of their potential impacts to reliability. NERC’s DER risk mitigation strategy is primarily designed to help stakeholders share their knowledge and push forward their collective expertise on the subject.
Core Tenets Underlying Strategy
The strategy comprises four core tenets. First is DER modeling; according to the report, SPIDER’s interactions with industry experts have “identified that a lack of DER modeling information, tools and established planning practices is limiting [utilities’] abilities to accurately incorporate DER models into planning assessments.” NERC said the group’s efforts in this category will primarily focus on industry guidance, but they will also require changes to reliability standards that relate to modeling in order to ensure planners have the appropriate DER data for modeling purposes.
Another tenet is to ensure that future studies of BPS reliability incorporate the effects of DERs in aspects including the pre-disturbance base case setup, selection of reliable contingencies and analysis of how aggregate DERs will respond to large-scale grid disturbances. SPIDER is currently working to develop a reliability guideline to encourage entities to account for DER growth in their studies; NERC is updating its standards to “ensure … requirements are adequate and clear on how to model, study and assess” the impact of DERs on planning assessments, with further standards updates likely to come in the future.
NERC is also studying the risks associated with the next core tenet, the operational impacts of DER — particularly as it relates to decentralization and the shift of significant amounts of generation to the distribution system. SPIDER is also developing a white paper focused on coordination between transmission and distribution entities to improve BPS reliability.
Finally, the last tenet of the strategy is the contribution of regulatory bodies, particularly FERC, to the conversation. NERC pointed to FERC’s Order 2222, which required RTOs and ISOs to open their markets to DER aggregations, as introducing “unique operational benefits and challenges for grid planners and operators” and showing that other stakeholders will not wait for the ERO Enterprise to take the lead on DERs. The report observed that further regulatory action may target other areas of the ERO’s purview, such as reliability standards, training and education, and cybersecurity.
OGE Energy management told financial analysts Thursday that it has completed its exit from the Enable Midstream Partners joint venture with the final sale of its interest units, allowing the company’s investors to focus on “a premium electric utility business.”
CEO Sean Trauschke did not sound disappointed during the company’s third-quarter earnings call that it would be the last in which he discussed midstream financial results, saying he wanted to “take a moment to reflect on the end of what has been a decade-long effort to close this part of our business and move forward.”
The company is using the proceeds from the sale to pay down short-term debt and plan for the future by protecting customers with an equal focus on reliability and affordability. It has also increased its storage positions to increase its physical supply of natural gas, one of OGE’s key learnings from the February 2021 winter storm.
“At the end of the day, we’re accountable to making sure that energy is flowing to all of our customers, and we want to control that,” Trauschke said. “We want to make sure that we’re in charge of that, and we don’t want to rely on others to support us.”
OGE reported earnings of $262.8 million ($1.31/share), as compared to $252.5 million ($1.26/share) for the same quarter a year ago, attributed mostly higher operating revenues driven by warmer weather. The earnings exceeded analysts’ expectations of $1.16/share.
The company’s share price was trading at $37.07 in after hours, a gain of 69 cents on the day.
To meet its target of 25 GW of offshore wind energy by 2045, California will need about 1,300 floating wind turbines, along with seaport sites to support production and operation of the massive structures, speakers said during a workshop.
Potential locations for those sites were the focus of a workshop on Monday hosted by the California Energy Commission (CEC). The commission is facing a June 30, 2023, deadline to complete a strategic plan for offshore wind, including a blueprint for improving waterfront facilities to support OSW development.
Seaport sites are needed for fabrication and assembly of wind turbine components, a process that requires sheltered harbor space, wide areas, deep, navigable water, and the capacity for heavy loads, said Matt Trowbridge, an engineer with Moffatt & Nichol, a port infrastructure consulting firm.
Other sites may serve as operations and maintenance facilities for the turbines once they’re in place, Trowbridge said during the workshop. These sites will ideally be as close as possible to the wind farms.
California will need an estimated 1,300 floating wind turbines to meet the 2045 target of 25 GW, Trowbridge said, and potentially 10 or more seaport sites to support them. One port might be able to accommodate multiple support sites, he noted.
Currently, California doesn’t have any such sites, he said.
“There is no existing port terminal on the U.S. West Coast that can currently support offshore wind,” Trowbridge said. “There’s space available in the ports, but no facility is adequate for offshore wind without significant investment.”
Searching for Sites
Trowbridge said 17 major ports and harbors have been contacted to see if they’re interested in participating in OSW and, if so, whether they have space to do so. The results of the survey are “promising,” Trowbridge said, but details won’t be released until the ports have a chance to weigh in on the findings.
Small craft harbors are also being explored as potential sites for OSW operations and maintenance.
“We’re trying to turn over every stone,” Trowbridge said. “We’re looking at every possibility to try to identify the pros and cons and the best path forward.”
But Trowbridge emphasized that the search for OSW support sites is not intended to displace existing uses. Rather, the study is looking for undeveloped or underutilized sites.
The discussion of OSW support sites comes as the U.S. Bureau of Ocean Energy Management plans a Dec. 6 auction of five leases off the Northern and Central California coasts. (See BOEM Sets California Offshore Wind Auction Date.) Two leases, with a combined potential for about 1.6 GW of wind energy, are in the Humboldt Wind Energy Area off the coast of Northern California. Three leases in the Morro Bay Wind Energy Area have a combined potential of about 3 GW.
Because the Morro Bay lease area is far from existing ports, the State Lands Commission is studying whether there’s a suitable site for a new port between the San Francisco Bay Area and Long Beach.
So far, that option doesn’t seem viable, although it hasn’t been ruled out, Trowbridge said. Much of the coastline was deemed unsuitable because it’s near a residential area, a military base, a state park or national forest, or a marine sanctuary. And while the study hasn’t been completed, it appears that building a new port in one of the remaining areas would be less feasible than developing a site at an existing port.
The port infrastructure study won’t stop at identifying potential OSW support sites. Additional steps will include looking at improvements needed at the sites and potential impacts.
Head Start at Humboldt
The Humboldt Bay Harbor, Recreation and Conservation District is actively exploring playing a role in the OSW industry, Rob Holmlund, the district’s director of development, said during the workshop.
Humboldt Bay’s Northern California location is between two wind “hot spots,” Holmlund said, and the harbor has the potential to support OSW in both the Morro Bay and Humboldt wind energy areas. The harbor lacks constraints such as limited channel width or depth, or bridges that could block turbine transport, he said.
The Port of Humboldt Bay developed a conceptual master plan for the site, which was followed in March by a $10.45 million CEC grant to prepare the bay for offshore wind. The grant will help pay for preliminary engineering and design work, site surveys and special studies, environmental impact assessments, early construction, and environmental mitigation.
Last week, the port announced it will exclusively negotiate with Crowley Maritime to develop and operate the Humboldt Bay Offshore Wind Heavy Lift Marine Terminal. The terminal will support tenants in the manufacturing, installation and operation of offshore wind floating platforms, as well as the use of large heavy cargo vessels and crewing and marshaling services in the ocean.
The agreement with Crowley involves a 98-acre Phase I, with an option for future phases.
AB 525 Requirements
Port infrastructure development is one piece of a five-part strategic plan for OSW required by last year’s Assembly Bill 525. Other sections of the plan will focus on sea space identification, transmission planning, permitting and potential impacts of OSW.
AB 525 also requires the CEC to determine the state’s maximum feasible capacity for OSW and set planning goals for 2030 and 2045.
FERC said Wednesday that ITC Midwest can keep the capital structure it has had in place since 2007, blocking an Alliant Energy-led complaint in the process (EL22-56).
Alliant’s coalition of Iowa utilities, industrial customers and consumer advocates in May challenged ITC’s capital structure as excessive and too skewed toward equity. They asked the commission to reduce ITC’s equity ratio to 53% and establish hearing and settlement procedures to grant refunds to transmission customers. (See Alliant Energy Leads Challenge of ITC Midwest Capital Structure.)
ITC Midwest, an independent transmission company, uses a capital structure reflecting 60% equity and 40% debt in its formula rate to calculate its overall rate of return.
FERC said the coalition did not prove that the utility’s existing capital structure is unjust and unreasonable. It ruled that ITC’s target capital structure is comparable with those used by other investor-owned MISO transmission owners and is not unusually high.
The commission also pointed to its policy of using the actual capital structure “of the entity that provides the financing, whether that entity is the utility or its parent company.”
Iowa customers argued that FERC’s approval of ITC’s 60% target equity ratio 15 years ago was “based on the expectation that ITC Midwest would have its own credit rating separate from its parent company,” ITC Holdings. They argued that both the utility and MISO have undergone seismic changes since the capital structure was approved, with ITC Midwest’s rate base increasing 550% since 2008 and ITC Holdings being acquired by Fortis, Inc.
Both the Iowa Utilities Board and the Minnesota Department of Commerce intervened at FERC in support of the complaint.
However, the commission said the Iowa customers didn’t establish that either ITC Holdings or Fortis guarantees ITC Midwest’s debt or that they would assume its debt obligations if the utility defaulted. FERC also said that contrary to allegations, ITC Midwest has a different bond rating from ITC Holdings and Fortis.
“Although ITC Midwest does not have its own management-level employees and relies on ITC Holdings’ management, this does not demonstrate that ITC Holdings guarantees ITC Midwest’s long-term debt,” FERC said.
With winter heating bills on the way, the Biden administration on Wednesday announced nearly $9 billion in funding from the Inflation Reduction Act to provide rebates to families for upgrading their homes with a range of energy-efficient improvements.
Announcing the new funding to a cheering crowd at a Sheet Metal Workers Union hall in Boston. Vice President Kamala Harris said the $146 million coming to Massachusetts will provide “rebates of more than $800 per household to help families purchase and install, for example, a new electric stove and … up to $1,600 per household to help families install new insulation. It means giving families up to $8,000 to replace their gas furnace” with a heat pump.
The funding connects “so many important priorities by helping families pay the upfront cost for energy efficiency upgrades to their homes,” Harris said. “We are also lowering energy bills, bringing down household costs, creating jobs and fighting the climate crisis.”
The rebate program could help to upgrade up to 1.6 million homes nationwide and install up to 500,000 heat pumps, according to a White House fact sheet. Harris estimated the savings per household at $500 a year; the Department of Energy said savings nationwide could reach $1 billion annually.
The DOE announcement provided more details on the funding, along with a list of allocations going to the states, ranging from more than $690 million for Texas to $59.4 million for the District of Columbia. Another $225 million is earmarked for a “high efficiency home rebate program” for tribal communities.
But those savings will likely not come this winter. Wednesday’s announcement allows states to “access information about their allocated funding and … begin planning programs to distribute relief to families, using these funds,” according to the White House.
The DOE release laid out a series of steps that will be taken prior to any actual distribution of funds. A series of “listening sessions” with states and “a wide array of stakeholders” will be held over the next three months, followed by a request for information early in 2023. DOE is targeting spring 2023 for getting the money to the states, with the public receiving rebates later in the year.
“States will have greater resources to meet their consumers’ needs and more rapidly achieve home electrification on the path to a net-zero emissions economy,” Energy Secretary Jennifer Granholm said in the release.
The rebate program is aimed at helping moderate- and low-income families with the upfront costs of energy efficiency improvements, Harris said.
The Details
The funding is divided between two programs: one providing home energy performance-based rebates and a second with rebates for high-efficiency home electrification, according to DOE.
For the performance-based rebates, homes that reduce energy use by 20% will be eligible for $2,000 in rebates, while a 35% cut in energy use will qualify for up to $4,000 in rebates. Those maximums will double for retrofits for low- and moderate-income households.
The rebates available for a high-efficiency electric home top out at $14,000 per household, with a $8,000 cap for a heat pump and $1,750 for a heat pump water heater, with all rebates paid at point of sale. Electric stoves and clothes dryers will also be eligible for rebates, as well as insulation and sealing measures.
The high-efficiency home rebates will also be based on family income relative to an area’s median income. A family earning 80% to 150% of the median income would qualify for rebates covering 50% of the cost of a specific upgrade, while households earning 80% or less of the median would receive a 100% rebate.
RACER
DOE also announced on Wednesday $43 million in funding for 23 projects that will “help communities plan their transition to a clean energy future and improve grid reliability and security.”
Most of the money will go to 20 projects under the Renewables Advancing Community Energy Resilience (RACER) program, which DOE said “seeks to enable communities to utilize solar and solar-plus-storage solutions to prevent disruptions in power caused by extreme weather and other events.”
For example, the Virginia Department of Energy is receiving $1 million for a project that “will identify opportunities to use distributed energy resources like solar-plus-storage in 10 different locations [in Southwestern Virginia] to maximize the benefits of energy resiliency infrastructure for disaster response needs.”
According to figures from the National Oceanic and Atmospheric Administration, the U.S. has sustained 15 extreme weather events with losses exceeding $1 billion each. Total costs are estimated at $30 billion, with “significant economic effects on the areas impacted,” DOE said.
The other three projects will focus on “building tools to help communities better evaluate and benefit from local energy resources,” DOE said. “Researchers will develop and share planning methodologies, tools, technologies and best practices that can be replicated in communities across the country as they work to install clean energy and strengthen grid infrastructure.”
“Knowledge is power, especially when it comes to giving local communities the tools to understand and make informed decisions about their own energy supply and needs,” Granholm said. “These critical projects will help deliver reliable, affordable energy to every pocket of America — strengthening the safety and resiliency of communities across the nation.”
Entergy on Wednesday said it is engaging with stakeholders as it prepares regulatory filings related to its proposed $15 billion, 10-year accelerated resilience plan to upgrade its system against future storm damage.
“We’ve invested in new infrastructure built to higher standards that will improve the system’s resilience,” CEO Drew Marsh told analysts during Entergy’s third-quarter conference call. “We expect our proposed investments to significantly reduce physical and financial storm risk.”
Marsh said the plan is “heavily informed” by Florida’s recent experience with Hurricane Ian.
“We did our homework,” the new CEO said. “Knowing that their hardened assets performed well in Hurricane Ian, along with the strong performance of our own hardened infrastructure over the past couple of years, gives us confidence that we can substantially reduce our exposure to storms and provide meaningful benefits to customers.”
The New Orleans City Council has already approved a $206 million securitization recovery for Entergy New Orleans’ Hurricane Ida costs and to replenish the company’s storm escrow. The company plans to file its resilience request in Louisiana by the end of the year and in Texas next year.
Entergy reported quarterly earnings of $561 million ($2.74/share), up from the same period a year ago when it delivered earnings of $531 million ($2.63). Marsh said the strong quarter allowed Entergy to cut 10 cents off its year-end adjusted earnings guidance, now $6.25 to $6.45.
The utility’s adjusted earnings of $2.84/share beat the Zacks Consensus Estimate of $2.67/share.
The earnings call was Marsh’s first as CEO. He replaced Leo Denault, who stepped down on Nov. 1 and continues to chair the company’s board. (See Entergy CEO Denault Stepping Down in 2023.)
CenterPoint Exceeds Expectations
CenterPoint Energy on Tuesday reported earnings of $189 million ($0.30/diluted share), a tick down from last year’s third quarter of $190 million ($0.32/diluted share).
The Houston-based company updated its capital expenditure plan by $2.3 billion to nearly $43 billion. CEO David Lesar said the incremental capital will be dedicated to further distribution system resilience, reliability and grid modernization, and transmission upgrades in its Houston Electric area.
CenterPoint’s adjusted earnings of 32 cents/share beat the Zacks Consensus Estimate of 31 cents, the 10th straight quarter Lesar’s management team has met or exceeded Wall Street’s expectations.
The company’s share price peaked at $28.93 on Tuesday before finishing at $28.11 on Wednesday, down 48 cents from its pre-announcement close.
ATLANTIC CITY, N.J. — PJM and the New Jersey Board of Public Utilities (BPU) are considering how to incorporate other states in future public policy transmission upgrades, an acknowledgement that the RTO’s State Agreement Approach could benefit “free riders,” officials told a conference Oct. 28.
The BPU voted Oct. 26 to award $1.07 billion in upgrades to deliver offshore wind generation to the PJM grid in the first application of the RTO’s State Agreement Approach. The SAA allows states to sponsor transmission to support their public policy needs while requiring them to pay 100% of the costs. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU’s award will fund onshore transmission upgrades needed to integrate 6,400 MW of offshore wind, but it does not include any offshore transmission and further upgrades will be needed to meet the state’s new offshore wind goal of 11 GW. As a result, the BPU directed its staff to begin a second round of coordinated transmission planning to meet the increased goal, potentially including a new SAA solicitation.
One question that needs to be addressed is how to allocate costs for non-New Jersey projects that want to bring energy to the system through upgrades funded by New Jersey ratepayers, Kris Ohleth, executive director of the independent Special Initiative on Offshore Wind told the Time For Turbines conference in Atlantic City.
Ohleth, who moderated a panel before an audience of 125, described a situation in which “New Jersey is paying for this type of upgrade to our system, and the region benefits from offshore wind” projects using it.
BPU Executive Director Bob Brabston, who appeared on the panel with Asim Haque, PJM’s vice president of state and member services, said the BPU is just beginning to consider the free-rider issue raised by Ohleth.
“No one wants to pay for something that they’re not getting the benefit of,” Brabston said. “And we feel like there are a lot of benefits that will flow out of New Jersey because of this. But it’s really conceptual at this point. So, in terms of what that would really look like in terms of how complex cost allocation can be, and the different perspectives among our fellow member states, it’s really early to say how that might work out.”
Brabston echoed BPU General Counsel Abe Silverman, who said in September that state officials hope to engage in “horse trading” with other PJM states over the cost allocation of transmission needed to meet their climate goals. (See NJ Foresees ‘Horse Trading’ with Other PJM States over Tx Costs.)
PJM’s Haque said the cost allocation issue is part of a “robust discussion” underway in the industry about how it can be more proactive in addressing state transmission build-out needs. “Electrons don’t know state borders,” he said.
“We’re finding ourselves in a space where there are multiple states that are actually sort of sharing similar policy initiatives, whether it’s renewable portfolio standards or offshore wind initiatives,” he said. “Generally speaking, PJM is supportive of the sort of long-term, long-range transmission planning. And we’re supportive of thinking about how the states can get more involved in determining what cost allocation should look like.”
That’s complicated because states are at “different sort of points on the spectrum,” he said.
“You’ve got states in the PJM footprint that say that we, we don’t want to pay a dime for something that didn’t arise out of our state legislature, or an executive order or whatever,” he said. “And you have some states in the middle that said, ‘Well, let’s look at all the different benefits that would arise from this project. And if some benefits would eventually find a way to our consumers, we can conceivably pay for it.’ And you have states that say, ‘You know, there are so many states that with similar policy objectives, it makes sense for a lot of our states to go at it together and share costs.’”
Cost Reductions Through SAA
New Jersey’s process was the first time that any state has used the FERC-authorized SAA process, and conference speakers said the results demonstrate the benefits of the approach.
The BPU approved $504 million for work in and around the Larrabee substation in Central Jersey to FirstEnergy’s Jersey Central Power and Light and Mid-Atlantic Offshore Development (MAOD), a joint venture of Shell New Energies US (NYSE:SHEL) and EDF Renewables North America (OTCMKTS:ECIFY). The state also will spend $575 million for other upgrades to accommodate OSW generation.
BPU officials say that the $1.07 billion price tag is about $900 million lower than the upgrades would have been without the coordination and competitive bidding overseen by PJM under the SAA. PJM’s solicitation generated 80 proposals from 13 developers.
Without the coordinated process and competition the transmission upgrades needed would evolve through “many developers, many projects proceeding on their own timeline with their own decision making, their own priorities,” Brabston said. That could mean some benefits, such as “a lot of innovation and competition, but also a lot of duplication, no economies of scale, and a lot of impacts on communities and on the environment,” he said.
Although the BPU sought proposals for connections on and offshore, the BPU funded only onshore projects, leaving the offshore work still to be allocated. The board expects the winner of the third solicitation, which is due to take place early in 2023, to include plans for the offshore connections that will tie future projects to the upgraded transmission facilities just approved by the board.
“One of the aspects of the project that we awarded is the expectation that all of the cabling access that’s required for all of the offshore generation that we expect to award in future solicitations will come through the same landing point,” Brabston said. “And that’s a way that future developers will know with certainty where they need to come onshore, and that that particular asset will be there already constructed.”
Haque acknowledged that the SAA prompted PJM to change its own strategy.
“We weren’t always in the space of trying to figure out how to help states,” he said. “PJM was not always the most friendly to state policy endeavors. And so for us to have gone from a space where we had [BPU] President Fiordaliso say, ‘We may not be seeing eye to eye with PJM in the future’ to where we are now: We jointly figured out a path to build transmission to bring offshore wind to New Jersey consumers …. I think it’s really wonderful.”
Helping to De-Risk
John Dempsey, CEO of Blue Point Wind, a joint venture between EDP Renewables and Engie, which won the auction for an offshore wind development lease in the New York Bight in February, said the initiative would also help developers and the industry as a whole. Speaking on a panel that focused on OSW project developments off the New Jersey coast, he said the state’s SAA was a “tremendous, tremendous effort.”
The initiative “really goes a long way at helping de-risk projects, which lowers costs,” he said. “The efforts made by the state earlier in the week, I think really go a long way at making New Jersey a really good place for offshore wind developers to land, so we were really pleased to see that.”
Dempsey, in an email after the conference, said that as states increase their offshore wind capacity targets the industry will need more “proactive transmission development” like the BPU’s initiative to make projects happen.
Blue Point Wind, also known as Ocean Winds East, paid $765 million for its New York Bight lease, giving the developer rights to an ocean parcel 53 miles off the New Jersey Coast that is expected to generate 1,700 MW of electricity. The project will sell its power to either New York or New Jersey and is evaluating “multiple interconnection scenarios” at each location, Dempsey said.
“The BPU award offers clarity to the industry on the optimal cable landfall location and the point of interconnection for the next round of projects, and it will ensure that there is sufficient transmission capacity on the system to accommodate offshore wind,” he said. “For developers like Bluepoint Wind, this clarity will reduce uncertainties in their projects and allow them to offer more competitive proposals to New Jersey in its upcoming solicitations.”
Reliability risks from the addition of variable resources to the Western grid will continue to grow, requiring greater planning reserve margins to mitigate the unpredictability of wind and solar generation, WECC said Wednesday in its third annual Western Assessment of Resource Adequacy.
Last year’s Western assessment showed a planning reserve margin indicator (PRMI) for the Western Interconnection of 16.9%. The 2023 PRMI increased to 18.3% in WECC’s latest assessment.
“Additional [variable energy resources] will cause the PRMI to increase further,” WECC said. “If nothing is done to mitigate the long-term risks within the Western Interconnection, by 2025 we anticipate severe risks to the reliability and security of the interconnection.”
Power producers plan to retire 26 GW of resources, mostly coal and natural gas plants, during the next decade and to add 80 GW of new resources, most of which will be solar and wind generation and battery storage.
“The resource mix in 2032 will look different than it does today, with much higher levels of variability,” the assessment said. “This is because resources like solar and wind are variable, meaning their energy output changes constantly and there is limited dispatchability.”
Severe weather events and rising temperatures add to the uncertainty, as do electrification, energy efficiency and emerging technologies, WECC said.
All “will affect how demand looks and behaves over the next decade,” it said. “This added uncertainty exacerbates the challenges facing planners and operators.”
WECC’s other measure of resource adequacy, its demand-at-risk indicator (DRI), showed fewer hours at risk of electricity shortfalls in the next few years. WECC measures DRI for every hour of the year for five subregions: California and Mexico, the Desert Southwest and three regions — central, northwest and northeast — of the Western Power Pool (shown as NWPP in the report).
“Compared to the 2021 assessment, the DRI for the Western Interconnection decreases through 2025 due in part to reductions in the load forecasts in the Pacific Northwest and northern Rocky Mountains, and in part to actions taken after the 2020 heat wave to strengthen resource adequacy,” it said.
“These actions include the addition of almost 3,000 MW of new or expedited resources, the vast majority of which is battery storage, and the delayed retirement of generator resources,” WECC said.
The delayed retirements included the 2,300-MW coal-fired Jim Bridger Power Plant in Wyoming, the 1,600-MW gas-fired Haynes Generating Station in Long Beach, Calif., and the 830-MW gas-fired Scattergood Generating Station in Los Angeles.
“Once these plants are retired, the risk returns and will need to be mitigated,” WECC said. “Delaying the retirements provides entities more time to determine how to mitigate the risks once these plants retire.”
After 2025, each WECC subregion shows an increase in DRI because of retirements in the next decade, the reliability organization said.
WECC introduced its Western RA assessment in 2020 to supplement NERC’s Long-Term Reliability Assessment because Western stakeholders were concerned that NERC’s analysis did not capture all the risks the Western Interconnection faces.
Like the NERC assessment, WECC’s Western assessment attempts to identify the biggest threats to the bulk power system over the next 10 years.
WECC has scheduled two webinars to discuss its findings, a high-level policy overview on Nov. 9 and a “deep-dive technical review” on Nov. 16.
WASHINGTON — The nuclear industry is out to change the conventional wisdom on building new nukes — specifically that such projects are always late, over budget and do not perform as expected.
The way forward, according to a panel of nuclear safety regulators at the International Atomic Energy Agency’s Ministerial Conference last week, will require harmonization of standards, international collaboration and a strong sense of urgency.
“Regulators are often perceived as barriers to efficient deployment of new-build [projects] and the adoption of new technologies and innovation,” said Mark Foy, chief executive and chief nuclear inspector of the UK Office for Nuclear Regulation. “I think it’s time for regulators to actually bust that myth.”
Rumina Velshi, Canadian Nuclear Safety Commission | IAEA
With the U.K. targeting 24 GW of new nuclear by 2050, “the future will see innovative technologies, innovative operating regimes and new organizational designs,” Foy said in his opening remarks as both panel moderator and participant. “As [regulators], we welcome these and are beginning to look at our approach and criteria for assessment and for licensing, and how they need to evolve in this new world.”
“A global industry will require global solutions,” he said, with alignment — or “harmonization” — of standards between countries a major topic of discussion within the industry.
Rumina Velshi, CEO of Canada’s Nuclear Safety Commission, agreed that as new technologies such as small modular reactors (SMRs) are rolled out, countries will need to develop a common framework that is technology-inclusive, performance-based and risk-informed. Achieving the scale and speed needed to meet climate goals will also mean short-term standardization of SMR design, Velshi said.
“SMRs will only work if we’ve got a reasonable number of technologies, not the more than 80 or 90 being considered,” she said. “Governments and industry [must] come together with a reasonable set of technologies … and standard designs that can deploy globally.”
Christopher T. Hanson, NRC | IAEA
While agreeing with Velshi on the need for whittling down the “plethora of new designs,” Christopher T. Hanson, chair of the U.S. Nuclear Regulatory Commission, argued for striking “a balance between harmonization and sovereign, national responsibilities. After all, each of us regulators will be regulating the reactors within our own borders and are responsible to our citizens.”
The NRC in August issued a design certification for the NuScale SMR to be built at the Idaho National Laboratory and is now reviewing the Kairos Hermes advanced reactor planned for Tennessee, Hanson said. He also stressed the need for “the continued and ongoing safe operation of the current fleet, overseen by strong, technically competent and independent regulators.”
Liisa Heikinheimo, deputy director general of Finland’s Ministry of Economic Affairs and Employment, also talked about the need for speed and flexibility in permitting processes as nuclear technologies continue to evolve.
Finland has set an aggressive goal of 2035 for carbon neutrality, Heikinheimo said, and SMRs will be needed “not only for electricity production but also to produce heat. This is a new feature, and it should be understood well from different angles. We need to build, most probably, units closer to cities and to be more flexible in operations to be compatible with renewables.”
Lisa Heikinheimo, Finland | IAEA
Representing the industry voice on the panel, Jay Wileman, CEO of GE Hitachi Nuclear Energy, also called for a new narrative for nuclear, saying that the industry must counter its late and over-budget profile. The only new reactors built in the U.S. in three decades, Georgia Power’s Vogtle plants, are years late, with an estimated cost of $30 billon, more than double the original cost estimate of $14 billion. The utility announced that one of the reactors started to load fuel in October and could begin operation in the first quarter of 2023.
Moving forward, the industry must be more competitive, Wileman said. “We have to come in with a design that’s at the right cost. To do that, you have to have a standard plant, a repeatable one that can be taken globally from one country to another, one regulatory overview to another, without redesigning every time.”
“You have to design to cost,” and deliver both on time and on performance, he said.
GE Hitachi is working with regulators in the U.S. and Canada on the permitting for its BWRX-300 SMR, which has been chosen for projects by TVA, Ontario Power Generation and SaskPower in Saskatchewan.
Clean, Firm, Dispatchable
The emerging international footprint for nuclear is now, at least within the industry, a given. According to multiple speakers at the IAEA conference, keeping climate change to 1.5 degrees Celsius and achieving worldwide carbon neutrality by 2050 will not be possible without the clean, firm, dispatchable power nuclear can provide.
The change in attitudes toward nuclear around the world “is palpable,” said Rafael Mariano Grossi, director general of the IAEA, in his opening remarks at the event on Wednesday. “Countries, important countries, at some point in their contemporary history thought nuclear energy would no longer be part of their energy mix, and we see countries reversing those decisions or decisively moving into nuclear because we have to be led by science, by economically feasible decisions and not by ideology.”
With nations in Africa and Latin America increasingly looking at nuclear, Grossi said, governments must “choose the right technologies, the right partners and provide the right framework for nuclear expansion.”
William D. Magwood IV, director general of the Nuclear Energy Agency of the Organization for Economic Cooperation and Development (OECD), said nuclear generation — both for electricity and process heat for heavy industry — will have to triple by 2050.
Announcements during and following the conference add to a growing narrative around nuclear as a core technology for energy security and economic development in the U.S. and worldwide.
Energy Secretary Jennifer Granholm closed the conference on Friday with an announcement that Poland had selected a U.S. bid from Westinghouse for the country’s first nuclear reactor. The decision, Granholm said, “sends a clear message to Russia that the Atlantic alliance stands together to diversify our energy supply to strengthen climate cooperation and resist Russian weaponization of energy.”
On Thursday, TerraPower, the advanced nuclear company founded by Bill Gates, and PacifiCorp announced their plans to explore deploying TerraPower’s Natrium advanced reactor to five sites in the utility’s service territory by 2035. The two companies are collaborating on the federally funded Natrium demonstration plant being planned for Kemmerer, Wyoming, at the site of a coal plant slated for closure.
The White House on Monday also announced a new clean energy partnership with the United Arab Emirates, with the “full-scale implementation” of civil nuclear technology called out as a key provision of the partnership framework.
‘High-quality Inputs’
While the U.S. continues to lead the world in nuclear power generation, China has moved into second place with 54 reactors currently in operation and another 22 under construction, according to the World Nuclear Association. As with other clean technologies, China has also developed a strong domestic supply chain, putting pressure on U.S. competitiveness in international markets.
Regulators at the IAEA conference faced questions about how long safety permitting should take and what companies and regulators need to do to keep projects on track.
Hanson said the length of the permitting cycle “depends on the quality of the input — if we have substantive pre-application engagement, if we get high-quality inputs. What does ‘high-quality inputs’ mean? It means show your work. Don’t just assert safety, show us; prove it in your application.”
Complexity and maturity of technology are other key factors, he said. One recent application, for a low-power reactor used to produce isotopes at a medical facility in Wisconsin, was reviewed in 24 months, Hanson said,
The NRC also recently released the draft environmental impact statement for the Kairos Hermes advanced reactor, 12 months after the project was first submitted. A final EIS is scheduled for the end of September 2023, according to the NRC website.
Velshi said Canada is also aiming for a 24-month turnaround for new advanced reactors.
At the same time, license extensions have become a major focus for U.S. and Canadian regulators, with projects in both countries looking to extend plant life to 60 or even 80 years. In the U.S., the NRC looks for “a rigorous and data-focused aging management plan … to ensure that as that plant proceeds into its longer life, it is doing so safety,” Hanson said.
The refurbishments needed for relicensing are often “massive projects that are probably equivalent to new-build projects,” Velshi said. The nuclear sector’s ability to deliver these projects on time and safely can provide “remarkable value in building confidence” for the public, investors and policy makers, she said.
Wileman agreed with the regulators on the need for high-quality applications, but he said, companies like GE Hitachi need “very good pre-submission discussions … really being able to go shoulder-to-shoulder and work the process collaboratively and make sure the dialogue is there; make sure everyone has a sense of urgency.”
“It’s important that the regulators and the industry understand the ambitions of one another and perhaps the challenges that each [faces],” Foy said. “But you can’t do it in isolation. You do have to come together and work on that end solution.”
