A federal jury in Chicago on Tuesday found former Commonwealth Edison (NASDAQ:EXC) CEO Anne Pramaggiore guilty of bribery in connection with a multiyear conspiracy to pay former Illinois House Speaker Michael Madigan (D) for passage of legislation favorable to the utility.
Also found guilty were former ComEd lobbyist and Madigan associate Michael McClain, former ComEd Vice President John Hooker and former ComEd consultant Jay Doherty.
The four were charged with nine counts of conspiracy to bribe Madigan in exchange for his help in passing bills that set certain rate charges that could not be debated before the Illinois Commerce Commission and produced millions of dollars of profits for the company over several years.
The conspiracy outlined by the U.S. Justice Department and now accepted by the jury included payments of about $1.3 million from the utility to pay contractors favored by Madigan but who did not work, and an arrangement to generate billable hours with a favored law firm that also did no work. ComEd also provided summer jobs for constituents in Chicago Ward 13, where Madigan resided, and the wards of Chicago aldermen allied with the speaker. The scheme also included an appointment of a candidate favored by Madigan to a seat on the company’s board of directors.
John Hooker, lobbyist and former ConEd executive | Chicago Housing Authority
Prosecutors during the trial referred to the payments as a “corruption toll” ComEd paid from 2011 to 2018.
Defense attorneys tried to convince the jury that the efforts of Pramaggiore and the others were just old-fashioned lobbying and not criminal.
A sentencing hearing must still be set. Each defendant faces up to five years in prison.
The guilty verdict came after five days of deliberations following a trial that lasted nearly eight weeks. The four were indicted on Nov. 18, 2020, after an eight-year FBI investigation that included hundreds of hours of wiretapped conversations. (See Ex-ComEd CEO, Officials Charged in Ill. Bribery Scheme.)
The verdict on all nine counts sets the stage for trials in April 2024 on federal racketeering charges filed against Madigan and his confidant McClain. The Justice Department indicted Madigan in March 2021.
Madigan was speaker of the Illinois House of Representatives for 36 years, the longest-serving leader of any legislative body — both federal and state — in the history of the U.S.
Dominion Energy Virginia’s (NYSE:D) new integrated resource plan anticipates continued development of solar, wind and storage and — much to the dismay of environmental groups — 970 MW of new natural gas capacity.
The company on Monday submitted its integrated resource plan to the State Corporation Commission, along with a planned rate cut.
“These plans demonstrate that solar, wind and storage will be the majority of the company’s generation development over the next fifteen years,” the IRP said. “Until new zero-carbon dispatchable generation options are developed or reach commercial viability, gas units are among the most affordable and reliable options for new generation that can quickly adjust output with changes in intermittent output.”
Reactions to the IRP
Gov. Glenn Youngkin (R) said the IRP shows the value of the kind of “all of the above” energy plan he supports.
“Virginia’s economy is growing, and the accelerated electricity demands of Virginia’s industrial users demonstrate the need for a more realistic and judicious approach to power planning,” Youngkin said in a statement. “We support an all-of-the-above approach that embraces the use of innovative generation technologies to bring more capacity online, while also thoughtfully managing the retirement of existing generation capacity to satisfy the growing needs of the commonwealth.”
Demand is projected to grow at 5% per year, which exceeds the expectations from when the 2020 Virginia Clean Economy Act (VCEA) passed. With PJM expecting retirements will outstrip new supplies in the coming years, Youngkin said “it would be a huge mistake” to retire baseload generation without a plan to replace it.
Advanced Energy United criticized the utility and its IRP for going against the intent of the VCEA, which is supported by the trade group’s members.
“We have seen this play from Dominion before. Its latest resource plan is yet another example of this utility picking a forecast that suits its business interests,” AEU Policy Director Kim Jemaine said in a statement. “Dominion chooses a questionable energy load forecast as justification for cherry-picking preferred technologies, preserving existing fossil-fuel facilities and calling for new investment in gas fired resources. In our view, Dominion has not developed a good faith decarbonization plan that fully aligns with the Virginia Clean Economy Act.”
VCEA was already designed to maintain reliability by relying on proven technologies and not requiring the retirement of natural gas until 2045, giving Virginia plenty of time to make the transition to 100% clean energy, Jemaine said. AEU wants Dominion to find ways to maximize the role of efficiency, demand response, smart rate design, rooftop solar and more technologies to rein in increasing demand.
“There are so many reliable and low-cost technology solutions to meet growing electricity demand, but they are largely absent from this new plan,” Jemaine said. “Instead, the utility is planning to preserve — even expand — natural gas-fired generation as a benefit to its shareholders, at unnecessary cost to Virginia consumers. This is a risky bet given volatile gas prices.”
The Integrated Resource Plan
Dominion’s IRP details ways the firm can meet its customers’ growing needs over the next 15 years — not an application to build specific projects, but a long-term planning document based on current technology and market information and projections.
Demand is expected to grow significantly faster over the next 15 years compared to the last as Dominion’s territory in Northern Virginia is home to a rapidly growing data center industry, and its customers are expected to electrify new sources of demand.
The firm’s plan is to continue developing renewable energy as required by the VCEA, while keeping most of its current power stations until the late 2030s.
“This ‘all-of-the-above’ approach ensures we can reliably serve our customers ‘around the clock,’ especially on the hottest and coldest days of the year,” Dominion Energy Virginia President Ed Baine said. “Our plan balances the benefits of renewables with the reliability of ‘on-demand’ power so we can meet the growing needs of our customers.”
The firm offered five long-term “alternative plans” that it said were developed using constraint-based, least-cost planning techniques and proven technologies:
Plan A is a low-cost alternative that will meet applicable carbon regulations and the mandatory Virginia Renewable Portfolio Standard (RPS), but does not meet the VCEA’s targets for solar, wind and energy storage. Dominion does not view it as a true path forward as it fails to meet state policies, but it noted that even without retiring most of its existing units, it still needed to construct significant new resources to meet demand. The utility forecast a net present value (NPV) of $109.7 billion for Plan A.
Alternative B is similar to A, but it meets the VCEA’s procurement goals and adds another 2.9 GW of combustion turbine generation, 19 GW of additional solar, 2.6 GW of additional offshore wind, 600 MW of onshore wind, 5.1 GW of storage, and 1.6 GW of small modular reactors (SMR). Even with the additional generation, Dominion would have to increasingly rely on imports, with plans to buy 4 GW from the market starting 2041 and beyond, requiring additional transmission. (NPV: $127 billion.)
Plan C is similar, but Dominion ignored VCEA requirements for in-state renewables. (NPV: $127 billion.)
Plan D leads to zero emissions as Dominion retires all carbon-emitting generation by the end of 2045. Plan D includes additional procurements to make up that gap with 3.4 GW of incremental solar, 4.6 GW of storage and 3.2 GW of SMRs. (NPV: $140.9 billion.)
Plan E is similar, but like Plan C it ignores the locational requirements of the VCEA. (NPV: $138 billion.)
“Plan D results in the company purchasing over 10.8 GW of capacity and 13 GW of energy in 2045 and beyond, raising concerns about system reliability and energy independence, including reliance on out-of-state capacity to meet customer needs,” the IRP said. “In addition, there is no guarantee that other states will maintain dispatchable generation that will be available for purchase when the company needs incremental power.”
Dominion table showing potential sources of supply under different scenarios | Dominion Energy
All the plans show that a growing capacity and energy need will require a diverse mix of resources and an increased reliance on market purchases, even under normal weather conditions and with few retirements.
Short-term Plan
Because the longer-term plan is full of uncertainties around technology and other issues, the IRP also included a short-term action plan for the next five years. Dominion said it plans to continue developing solar, onshore wind and storage while completing the Coastal Virginia Offshore Wind project on schedule by 2026.
The firm also plans to continue its efforts to get a license extension for the North Anna Nuclear Plant, developing 970 MW of new gas-fired combustion turbines; start development of a “backup” LNG facility to support reliable operations of its natural gas plants, and continue compliance with both North Carolina’s and Virginia’s environmental laws.
The Chesapeake Climate Action Network (CCAN) also panned the IRP. “Included in the IRP is a push for small modular reactors, a new nuclear reactor prototype that costs up to $10 billion each at a nameplate capacity of 300 MW of electricity and is currently operational only on one floating barge in Russia. A solar facility costs 3% as much per megawatt of nameplate capacity,” the group said.
CCAN also criticized Dominion for considering scenarios in which it would abandon the VCEA’s goals. “All iterations of the IRP assume that Virginia will exit the Regional Greenhouse Gas Initiative by 2024, despite a lack of legal authority for Virginia to do so without the approval of the legislature,” it said.
“We should recognize this unholy union between billionaire Governor Youngkin and Dominion for what it is: a corporate profit grab that would bankrupt Virginians and exacerbate climate change,” CCAN’s Virginia Director Victoria Higgins said. “The state can meet demand without compromising our clean energy goals or forcing Virginians to choose between energy and food. Suggesting new fracked gas infrastructure in 2023 is patently absurd.”
Rate Cut
The firm’s rate decrease would save the typical residential customer between $7 and $14/month because of bipartisan legislation that eliminated $350 million in riders while giving the SCC more flexibility to set its rates going forward. (See Virginia Legislature Passes Utility Regulation Bills Backed by Dominion.)
“Earlier this year we promised substantial rate relief for our customers,” Baine said in a statement. “Thanks to bipartisan legislation and broad support from consumer advocates, we are delivering on that promise.”
Dominion also asked to securitize some fuel costs so they will be recovered from customers over a longer term, which will lower monthly bills by another $7 starting July 1. The savings are partially offset by a $2.67 increase to the stand-alone transmission charge that would go into effect September 1 if approved, meaning the typical residential customer would save between $4 and $11 a month.
Electric truck maker Lordstown Motors (NASDAQ:RIDE) warned investors this week that it may seek federal bankruptcy protection following the refusal of major shareholder Foxconn to invest as much as another $117 million in the Ohio company.
“We may need to curtail or cease operations and seek protection by filing a voluntary petition for relief under the Bankruptcy Code,” Lordstown warned investors in a U.S. Securities and Exchange 8-K filing Monday.
The fledgling truck maker’s share price has fallen below $1/share, and it could be delisted from trading.
Monday’s announcement accelerated the decline of Lordstown’s share price, which fell below $1 on March 7 and remained there for 10 days, prompting the Nasdaq to warn on April 19 that it would delist the shares unless the price recovered to more than $1 for 10 consecutive days by Oct. 16.
The company made the Nasdaq’s warning public in an 8-K the same day it received it.
That prompted Foxconn to put the brakes on additional investments until the share price increased, declaring in a letter to the company on April 21 — only publicly revealed in this week’s 8-K — that Lordstown had breached an agreement made in November 2022 obligating Foxconn to invest up to $170 million in share purchases. (See Lordstown Motors Gives 2 Board Seats to Foxconn.)
Foxconn purchased $22.7 million of common stock and $30 million in preferred stock in November, according to Lordstown, and is now obligated to invest another $117.3 million in additional stock, according to the 8-K.
Foxconn, however, argued in its letter that the action by Nasdaq put the company in breach of the agreement; Lordstown replied that Foxconn cannot unilaterally pull out of the agreement.
“The company is in discussions with Foxconn to seek a resolution regarding these matters; however, to date, Foxconn has declined to revoke its invalid termination notice and has failed to confirm that it will proceed with the subsequent common closing or any preferred stock closing,” Lordstown wrote to the SEC. If the additional investments “do not occur, the company will be deprived of critical funding necessary for its operations.”
Foxconn said in a statement Tuesday that it remained open to continuing negotiations with Lordstown.
The two companies have been developing one electric vehicle, the Endurance pickup truck, which they hope to sell to commercial customers. Production of the truck has been repeatedly slowed or stopped by parts shortages and inadequate funding. Fewer than 40 trucks have been fully assembled. A recall in February to replace suspect parts in the few trucks that had been sold did not help the company’s reputation with investors. (See Lordstown Motors Recalls Endurance Electric Truck.)
Monday’s announcement of a possible bankruptcy filing accelerated the decline of the company’s share price, which tumbled to 25 cents midday before rebounding, ending the day at 39 cents. The share price on Tuesday was hovering in the mid-40-cent range. Over the last 52 weeks, the price was as high as $3.73, still a steep decline from a high of $31.40 in September 2020.
Public Service Enterprise Group (NYSE:PEG) should get a boost from New Jersey’s second solicitation for offshore wind transmission upgrades and the state’s deepening embrace of electric vehicles, CEO Ralph A. LaRossa said during a first-quarter earnings call Tuesday.
Of particular benefit to the company could be a recommendation by the state Board of Public Utilities (BPU) that cables running from offshore projects pass through the utility’s 500-kV Deans substation in Northern New Jersey, LaRossa told analysts.
“What it means for us certainly is that if PJM does agree with the Board of Public Utilities and selects that, any of the work inside the fence will be the responsibility of [PSEG utility subsidiary] PSE&G,” he said. “Outside the fence will still follow under that state agreement approach and be competitive solicitation.”
“What I’m encouraged by is the fact that Deans is in our service territory; we know our service territory; and we should be very knowledgeable about the routes to get from the shore to that substation,” he said.
PSE&G was among 13 developers that submitted 80 proposals in the state’s first solicitation, made under the FERC State Agreement Approach rules, which resulted in last October’s awarding of contracts totaling $1.07 billion. PSEG submitted several proposals, some with Danish OSW developer Ørsted, which is developing two of the three approved projects off the Jersey shore under the name Coastal Wind Link. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
Despite PSEG’s anticipation that it could see up to $3 billion in business from the solicitation, the BPU awarded the utility only two small contracts totaling $40.3 million. (See PSEG Sees Potential $3B OSW Transmission Spending.)
LaRossa said he was “very happy” the utility had upgraded its transmission network because BPU’s recommendation to use Deans indicated “that our transmission system is robust enough to take that injection of offshore wind generation into it.”
“Our engineering team has done a really nice job of readying the system for what might come, and here it is,” he said.
One analyst on the call noted that a major part of the business awarded in the first solicitation went to FirstEnergy’s Jersey Central Power and Light, which was contracted to build a new substation next to its existing Larrabee substation. The analyst suggested that might happen with PSEG and its Deans substation.
But LaRossa said only that the work already done has improved the utility’s “readiness” for the future.
Growing EV Use
LaRossa said the utility also is “developing proposals to help support and advance” New Jersey’s updated and expanded clean energy policy, which PSEG expects will be primarily implemented by the BPU. The utility is paying particularly close attention to three climate change-related executive orders signed by Gov. Phil Murphy in February, including one to bring about electrification of 400,000 homes by 2035 and to require all electricity sold in the state to be derived from clean sources by the same year.
Another measure would end the sale of gas-powered cars and light-duty trucks by 2035.
LaRossa said the company is seeing signs that the state is turning to EVs.
“We are starting to see some new business requests come in,” he said. “We see it in some of the Garden State Parkway rest stops. We’re seeing it in the New Jersey Turnpike rest stops. We’re seeing it in some of the large commercial organizations that were just granted approval by the BPU, that will install the charging infrastructure.”
“We’re going to keep an eye on that and see about what kind of capital is required for each one of those installations on a standalone basis to help us in projection going forward. But it’s just the start,” he said.
LaRossa added that he expects more information will become available over the next 12 months as the company deploys more advanced metering infrastructure, which uses smart meters to collect and communicate energy use data, and as “we start to see folks connect their EVs.”
He said he was “really excited” by the apparent interest in EVs, especially after the BPU on April 24 announced the recipients of the first round of grants under its Electric Vehicle Tourism Program and opened a second round of grant applications. The program provides funding to support the installation of EV charging stations at tourist sites around the state. In the first round it awarded $755,000 to 16 applicants who together will install 43 chargers.
Cash Flow from Nuclear
LaRossa said PSEG is looking to evaluate how it might boost the capacity of its three South Jersey nuclear plants in the second half of this decade.
Asked by an analyst about the future of the nuclear fleet, LaRossa said, “We want to and expect to keep those assets in our portfolio. I don’t see any scenario that we’ve been presented with that would make us waver from that.
“They are a great cash flow. They’ve been run really, really well. And they continue to be run really well,” he said. “And so, when you have that operating excellence, combined with the cash flow, it does create a very unique utility-like revenue stream for us that we think differentiates us from some of our peers.”
Company officials said they are awaiting direction from the U.S. Treasury Department about how to handle different aspects of the nuclear Production Tax Credit (PTC) approved under the Inflation Reduction Act. When that becomes clear, the utility can work out how that will affect the economics of its three plants and the future of the subsidies they receive under the state’s Zero-Emission Certificate program. (See NJ Nukes Awarded $300 Million in ZECs.)
“One of the things that we were saying that was so, so important is that we have a long-term solution for nuclear,” said PSEG CFO Dan Cregg.
He said the company was “happy” that the PTC created a long-term solution for profitably operating nuclear plants.
Earnings
PSEG reported first-quarter net income of $1,287 million, ($2.58/share) compared to a loss of $2 million ($0.01/share) for the first quarter of 2022. Non-GAAP operating earnings for the first quarter were $695 million ($1.39/share) compared with non-GAAP earnings of $672 million ($1.33/share).
LaRossa said the results show the company “delivered solid operating and financial performance to begin the year, and we are on track to achieve our full-year 2023 non-GAAP Operating Earnings guidance.
“We are executing our plan to grow PSEG while also increasing its predictability,” he said.
VALLEY FORGE, Pa. — PJM stakeholders provided feedback to the Board of Managers on a potential review of the Independent Market Monitor contract during the Markets and Reliability Committee meeting Wednesday.
Manager David Mills said the current deliberations are focused on the structure of the contract, not the performance of the current contract holder, Monitoring Analytics, nor whether the company will continue to hold the contract.
“It’s been quite some time since these documents were reviewed, and in that time, PJM has had a significant amount of turnover on the board,” Mills said. “This is not a performance review or referendum on Monitoring Analytics.”
Paul Sotkiewicz, president of E-Cubed Policy Associates, pushed for the board to consider issuing a request for proposals.
“If it turns out Monitoring Analytics is the best outfit to do this, that’s great … but I do think this should be open to a competitive process,” he said.
Vitol’s Jason Barker said the contract states that the PJM board has the responsibility to evaluate the Monitor’s performance, but it doesn’t provide any measure to benchmark against. He advocated for a third party to be retained to look at topics such as whether Monitor comments are pertinent and influence the outcome of FERC orders, and the impact of Monitor participation in the stakeholder process.
“We encourage the board not only to retain this provision … but also to use it,” he said.
Susan Bruce, of the PJM Industrial Customer Coalition (ICC), said the cost of market manipulation in PJM’s market is high and customers are willing to pay for a monitor who can push for stronger competition. While she said discussion of the Monitor’s role is appreciated, she cautioned against holding an RFP, saying that continuity is critical to the IMM’s work.
“There’s a place here for history and understanding how the markets work,” she said.
The topic of reviewing the contract was first raised in the board’s Competitive Market Committee. Mills, the committee’s chair, reiterated the board’s commitment to a monitor empowered to curtail market manipulation.
“None of this is intended to tear apart or destroy the foundation of a strong market monitor,” he said.
The board had previously solicited stakeholder input through the Liaison Committee and last month at the Organization of PJM States Inc.’s meeting, where Mills said comments addressed data access, intellectual property rights for proprietary software and calculations used by the Monitor, and how the contract handles succession.
Mills said the board plans to provide a public written summary of the comments it has received this month.
KANSAS CITY — SPP’s Board of Directors last week approved the scope of a team formed to address resource adequacy challenges and endorsed the group’s plans for dealing with resource accreditation.
SPP’s board and its state regulators created the Resource and Energy Adequacy Leadership (REAL) Team earlier this year. It was clear then to stakeholders that the group had a monumental task in front of it.
The team is charged with providing guidance, prioritization and policy recommendations to increase the assurance that energy can be continuously and cost-effectively provided within SPP’s balancing authority footprint. The team is also expected to address applicable recommendations from the RTO’s grid-of-the-future work and resource-adequacy issues identified by other initiatives.
When REAL Team chair and Texas Public Utility Commissioner Will McAdams found himself staring at a slide during an April 24 presentation to the Regional State Committee, he paused momentarily.
“And this is our implementation calendar,” McAdams said. He paused again. “This is an aggressive calendar, and we’re going to do our best.”
Kansas commissioner and RSC chair Andrew French said the team’s task is even larger than he first imagined in preparing the initial draft scope.
“I knew it would be a heavy lift, but as I’ve listened in on a couple of the first meetings and realized how important these issues are to everyone and how many extra issues there are, we’re realizing it’s going to be a heavy lift,” he said. “I’m more convinced than ever that it’s a worthwhile lift, that strategically, it’s absolutely essential to set the foundation for us moving forward.”
The REAL Team plans to deliver adjustments to SPP’s resource accreditation policy in October. FERC in March rejected SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds and granted clean energy interests’ rehearing request of its prior acceptance. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)
Next year, REAL plans to produce a resource adequacy methodology and related policies, a seasonal resource adequacy construct, value-of-lost-load and expected-unserved-energy metrics, and future capacity accreditation and planning reserve margins.
No wonder McAdams drew chuckles when sharing the team’s deliverables timeline.
“All of this we hope to tackle in year one,” he said.
McAdams said the 14-person team, comprised of SPP board members, stakeholders and state regulators and staff, will be “looking at challenges resulting from resource mix changes, high intermittent energy penetration into the system, and how our [load-responsible entities] can cope with that to ensure a reliable reliability standard is ultimately met.”
“This needs to occur during events of extreme weather, increased demand and evolving customer behavior,” he said. “REAL Team over the next year and possibly onward, will provide guidance, prioritization and policy recommendations to increase assurance that there will be sufficient energy to cost-effectively meet load requirements.”
The RSC last week unanimously approved the REAL Team’s scope. It also endorsed its proposal to respond to the FERC ruling — having the Supply Adequacy Working Group (SAWG) break effective load-carrying capacity (ELCC) and performance-based accreditation into two separate revision requests. REAL said the ELCC change should reflect FERC’s guidance to add a definition of seasonal net peak load and address the accreditation of renewable and thermal resources in a similar manner.
The proposal further directs SAWG to harmonize the two RRs and explain how the treatment of resources is equitable and appropriate, filing both changes with the board and RSC before the October governance meetings.
The Board of Directors approved the motion April 25 as part of its consent agenda.
“This shows us that we need to better describe our methodology with repackaging and re-presenting this policy to the FERC,” McAdams said. “Ultimately, we need to make an attempt to compare them on an apples-to-apples basis, even though the resources are different.
“My hope as chair … is that we start thinking about what FERC can approve in a timely way. These are important policy building blocks that we need to have in place in order to move off first base toward a reliability framework that we can actually defend and build upon and that we can hold the system accountable to,” he added. “We do not want to offer them proposals that they can just reject out of hand, which costs us time that we do not have. We need to be crafting proposals that have a degree of certainty that [they] will be passed.”
Member Value Up to $3.787B
SPP staff updated its member value statement during the quarterly stakeholder briefing that followed the RSC meeting, saying its analysis found the RTO provided $3.79 billion in net savings to members in 2022, a 41% increase from the year before and a 22-to-1 return on investment.
According to the report, the biggest savings came from the Integrated Marketplace’s day-ahead, real-time and transmission markets ($2.3 billion) and reduced costs and required reserves within the RTO’s footprint ($1.03 billion).
“That’s driven mostly by significant increases in the cost of gas and wholesale energy … [When prices rise] the benefit of participating in SPP’s [markets] obviously goes up,” said Mike Ross, SPP’s senior vice president for external affairs and stakeholder relations.
Ross said the market benefits are estimated by comparing what the cost of energy would be in the legacy balancing area versus SPP’s Integrated Marketplace.
“We’ve already seen much lower energy prices to start 2023,” he said.
The annual statement, based on a methodology developed by staff and stakeholders, quantifies the value SPP provides member organizations through reliability coordination, regional transmission planning, market administration and other services.
“This remarkable benefit-cost ratio demonstrates we are driving value beyond reliability,” CEO Barbara Sugg said.
In other quarterly reports:
SPP said it established new marks for wind energy and renewable energy on March 16 when it hit 23.8 GW and 24.89 GW, respectively, breaking records set in February. The grid operator has more than 32 GW of available wind resources.
Xcel Energy (NASDAQ:XEL) subsidiary Public Service Co. of Colorado’s April entry into the Western Energy Imbalance Service (WEIS) market has tripled its size to more than 13 GW. The utility’s load topped 6 GW in April, while WEIS’ weekly average this year has regularly been above 3.5 GW. A recent report revealed the WEIS market provided $31.7 million in net benefits to its 12 participating utilities in 2022 at a benefit-cost ratio of 7-to-1.
SPP’s Integrated Marketplace now has 195 financial-only and 119 asset-owning market participants, for a total of 314.
The West’s heavy snowpack from this winter will be partly soaked up by soils parched during years of drought, limiting hydropower production throughout the summer in the Desert Southwest and Pacific Northwest, speakers said during WECC’s annual summer outlook webinar on Wednesday and Thursday.
The two-day event offered a preview of summer conditions and operations in the Western Interconnection, with subjects that also included wildfires and extended weather forecasts.
“While we may have an increased amount of runoff initially, it doesn’t mean that that runoff is just going to stay there unimpacted by the dried soils of the last couple of years,” Sunny Wescott, lead meteorologist at the federal Cybersecurity and Infrastructure Security Agency, said in Wednesday’s session. “Watching that snowpack melt, come down the mountains and get absorbed rapidly is going to be a condition that everyone needs to be aware of.”
Clayton Palmer, an environmental specialist with the Western Area Power Administration, said the Southwest’s decades-long “mega drought” has meant that since 1988, less water has reached hydroelectric reservoirs in a region where “water equals power.”
“There’s much less runoff for every millimeter of water that has fallen as precipitation during the winter period” from October through April, Palmer said.
Lake Mead and Lake Powell on the Colorado River have risen this winter as snow blanketed the Rocky Mountains, but the hydroelectric reservoirs remain significantly below their historical averages, he said. The Bureau of Reclamation is examining options for maintaining hydroelectric production at Hoover Dam, which has a 2,074-MW generating capacity, and Glen Canyon Dam, with a 1,320-MW capacity, in what is expected to be a drier future for the Colorado River Basin, he said.
“We shouldn’t be using the word ‘drought’ since the word drought implies that something is temporary, that we have less water for a temporary period of time,” Palmer said. “What we have is a ‘drought,’ to use that word in quotes, caused by an increase in temperature.
“The Colorado River Basin has increased in average temperature by 2 degrees Fahrenheit, and higher temperatures cause snowmelt to be absorbed in drier soils,” he said. “The higher temperatures increase the dryness of the soils and increase evapotranspiration of the water that falls as snow … and decreases what we call the runoff efficiency. The runoff efficiency is how much of the water that falls as snow in the Colorado River Basin gets into the river.”
Forecasted annual generation in the Colorado River Storage Project, which consists of Glen Canyon and other dams in the upper Colorado basin, for 2023 through 2027 will hover around 4 million MWh, compared with an average of about 6.5 million MWh from 1971 through 2000, Palmer said.
In the Pacific Northwest, precipitation was 20% below normal this winter, but temperatures were lower, meaning “our snowpack generally throughout the Columbia River Basin is above normal,” said Geoffrey Walters, senior hydrologist with the Northwest River Forecast Center.
“On the other hand, another primary component to water supply volume forecasts is the soil conditions, and the soil conditions have been dry, and they’ve been dry throughout the winter,” Walters said. “And because of those dry soil conditions, water supply volume forecasts are lower than maybe what you would perceive just looking at the current snowpack. That’s because when soil moisture is drier than normal, it [takes] more of that melting snowpack before it allows the runoff to enter the rivers.
“Vegetation is also going to take more of the snowpack from the available downstream supply for power production or other uses,” he said.
The center is predicting water supply that is 83% of the normal April-to-September volume at Grand Coulee Dam, which has a generating capacity of 6,809 MW. At the Dalles Dam, which has a 1,780-MW capacity and is a key measuring point for Columbia River water flow, supply will be 85% of normal this summer, Walters said.
Wildfire Outlook
On Thursday, WECC took up the topic of wildfires.
While wildfires are not exclusive to the West, they are “a particularly Western concern,” Vic Howell, WECC director of reliability risk management, said Thursday in opening a panel on summer wildfire preparations.
Howell asked panelists about the biggest concerns their utilities have related to fires.
Chris Potter, control center real-time manager with AltaLink, said it’s all about “location, location, location” for the Alberta, Canada-based transmission provider, indicating that risks vary by geography.
Potter described the region’s “Chinooks,” a weather phenomenon occurring in the southern part of the province in which warm and dry westerly winds blow off the Rocky Mountains onto the prairie, rapidly elevating temperatures by as much as 50 F. Wind speeds during those events can reach 60 mph, he said.
“The biggest risk for us is that wind, because if we were to have a line that goes down, which is obviously more probable, in the high wind conditions … [if it starts a fire], it’s going to spread very, very quickly and cover a lot of ground,” Potter said.
Alberta also faces a risk of utility pole fires, he said, particularly along highway corridors lined with wood poles supporting wooden cross-arms. These fires are usually the result of automobiles kicking up dust containing road salt, which causes deterioration on the transmission line insulators, increasing the risk of line arcing under damp conditions, which can set fires to the poles.
“Wind-driven events” present the biggest risk in Southern California Edison’s 50,000-square-mile territory, nearly 30% of which is considered at high risk of wildfire, according to Raymond Fugere, the utility’s director of wildfire safety. Fugere pointed to two “big drivers” of wind-driven fires for SCE: when airborne “foreign objects” come into contact with power lines, causing them to fall; and “line slap,” which can eject molten particles onto the ground and ignite fires.
Christopher Sanford, senior system operator with the Bonneville Power Administration, vouched for the foreign object risk.
“When I was a system operator, getting a call that a trampoline is hanging in a line 40 feet above the ground, it’s kind of bizarre, but those things do happen,” Sanford said, adding that BPA is seeing high winds more frequently now than even 10 years ago.
“We can see a microburst with 100-mph winds and dry lightning, and that’s a great combination for starting fires,” he said.
As a federal power agency that operates about 15,000 miles of transmission but no distribution lines, BPA is also concerned about having clear communication and coordination with other entities in the region during high fire-threat events.
“BPA’s actions are influenced by what other utilities do, whether it’s an adjacent [transmission operator], or it’s one of our distribution customers. … Our impact when we take out a line under a public safety power shutoff [PSPS] can be far greater than a local area impact. [If] we take out significant transmission for wildfire prevention, that could impact down into California and up into Canada,” Sanford said.
System Hardening
Turning to the subject of potentially new challenges Western utilities will face during the upcoming wildfire season, Fugere pointed to the fact that while 95% of California was in drought conditions a year ago, that figure has dropped to zero after a winter of heavy rain and snow.
“So that is going to present some very unique challenges,” Fugere said, including an increase in “grass crop growth,” which elevates the risk of roadside fires ignited by cars. This will require the utility to adjust its schedule for “structural brushing,” the process of clearing grass and brush around the base of utility poles to prevent sparks from setting fires. The increase in soil moisture this year means the grass will grow back after an initial clearing.
Sanford said that while Northwest winter precipitation levels were not as extreme as in California, the season was wet enough to pose particular concerns for the grasslands of central Oregon and Washington.
“We do take on similar actions with system hardening with clearing around wood poles, [and] clearing and using other techniques to preserve wooden poles to reduce the impact of an outage,” Sanford said. “We’ve also done a lot of hardening around our substations,” including clearing brush to a perimeter of 50 feet where permitted. He said such actions have in the past created “well defended” areas that can function as a fire command post.
Fugere and his colleague Cameron McPherson extolled the success of SCE’s wildfire prevention efforts. Fugere said the utility has seen a 98% reduction in the number of structures burned within its territory since initiating fire-hardening measures in 2017, even while facing more extreme drought conditions.
“Our insurance company has told us that we reduced our risk for catastrophic wildfires probably by about 80% — of have a fire that will hit a billion dollars [in costs]. So that’s the mark we’re really driving towards also. We want to continue to drive that down as far as we can,” Fugere said.
McPherson, SCE’s principal manager for PSPS operations, said the utility’s efforts have significantly reduced the need for shutoffs, relegating their use to the most extreme weather events.
“Although used sparingly, due to the impact it has on our customers, there’s no doubt it’s extremely effective once we de-energize the lights,” he said. “The question then becomes, was there a potential fault condition on the line, had it been energized, that could have led to a catastrophic wildfire?”
McPherson said the findings from post-PSPS patrols indicate that SCE’s hardening efforts are paying off. He thinks the utility may even have the opportunity to raise the wind-speed thresholds for invoking PSPS in order to reduce their “scope, frequency and duration.”
One of the two men charged with attacking electric substations in Washington state over the Christmas holiday has pleaded guilty to conspiracy to damage energy facilities, federal prosecutors said on Friday.
Matthew Greenwood of Puyallup, Wash., filed his guilty plea Friday with the U.S. District Court
for Western Washington, according to a statement. In the plea, Greenwood admitted to vandalizing four substations owned by Puget Sound Energy and Tacoma Power on Dec. 25. In addition, the plea said Greenwood and his co-defendant Jeremy Crahan, also of Puyallup, planned to cut down trees “to take out power lines,” although this plan was not acted on before the two were arrested.
Greenwood said he and Crahan sought to disrupt power in order to break into ATMs and local businesses to steal money, the same motive he mentioned to the officers who arrested him on Dec. 31. (See Feds Charge Two in Wash. Substation Sabotage.)
He also faced a charge of possessing unregistered firearms; a spokesperson for the Department of Justice confirmed that Friday’s guilty plea was only for the charges related to the substation damage. The plea agreement included a pledge from the U.S. Attorney’s Office for the Western District of Washington “not to prosecute [Greenwood] for any additional offenses known to it as of the time of this plea agreement” based on “the promises made by” Greenwood.
Crahan was also charged with conspiracy to destroy an energy facility. According to court records, he has not entered a plea. The conspiracy charges carry a maximum sentence of 20 years for both men, along with a fine of up to $250,000 and three years of supervised release, although the Justice Department said prosecutors will “recommend the low end of the [sentencing] guidelines range when Greenwood is sentenced.”
Greenwood was released on bail at the end of January to attend drug treatment.
Pair Damaged Multiple Facilities
According to the plea agreement, Crahan drove Greenwood to the substations and Greenwood performed the actual attacks. Their first target was the Hemlock substation in South Hill, where Greenwood cut through the perimeter fence around 2:30 a.m., manipulated a bank high side switch, and damaged additional equipment, causing an outage for about 8,000 customers.
Surveillance photos from Tacoma Power showing Greenwood at the Elk Plain substation. | Tacoma Power
The pair then drove to the Elk Plain substation about nine miles away in Spanaway, arriving around 5 a.m. Greenwood cut the padlocks on the exterior gate, manipulated the high side breakers, and damaged additional equipment. They arrived at the Graham substation about 30 minutes later, where Greenwood again manipulated a bank high side switch and damaged equipment. Together, the damage to the Elk Plain and Graham facilities caused at least 7,500 customers to lose power.
Finally, Crahan drove Greenwood to the Kapowsin Substation, also in Graham. Greenwood tampered with the facility’s bank high side switch and tried to pry open the linkage, causing sparks and flames. No outages were attributed to this attack in the plea agreement.
This was not the end of the men’s plans; they intended to continue causing outages by cutting down trees that would then fall on power lines. Although the men spent some time with a chainsaw looking for trees to cut over the next several days, the FBI tracked them down using cell phone records and surveillance photos before they could do so.
Greenwood’s arrest statement said that he and Crahan burglarized a local business and stole from its cash register during the outage, but this incident was not mentioned in the plea agreement.
The Washington sabotage was one of several physical security incidents late last year, most prominently the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days. (See Duke Completes Power Restoration After NC Substation Attack.)
In response to the North Carolina attacks, FERC ordered NERC to review the effectiveness of its physical security reliability standards and determine whether improvements are needed. NERC released its report last month, identifying several possible areas of improvement and proposing a new standards development project to address the issues. (See NERC Says Changes Coming to Physical Security Standards.)
Vermont Gov. Phil Scott (R) plans to veto clean heat legislation for the second year in a row.
Scott said Friday that he agrees with the need to reduce greenhouse gas emissions, including in the heating sector, but the complex clean heat credit system approved by the state legislature is the wrong way to go about it.
The Affordable Heat Act (S.5), sponsored by Sen. Christopher Bray (D), would harm those who cannot afford to switch to cleaner forms of energy, Scott said, adding that Vermont should instead help its residents make the expensive transition, rather than financially punish them.
“Unfortunately, the Super Majority in the Legislature decided to take a completely different approach by giving an unelected commission, the Public Utility Commission, the power to design and adopt a system without guaranteeing the details and costs will be debated transparently through the normal legislative process, in full view of their constituents,” he said in a statement.
The General Assembly approved the measure last week with votes of 20-10 in the Senate and 98-46 in the House, both chambers falling short of unanimous support from their Democratic supermajorities.
A similar clean heat measure advanced through the legislature last year. Scott said then he would support that bill if its language explicitly required the policy details and projected costs of a credit system to come before the legislature and him for final approval.
Scott in his news release urged Vermonters to ask their representatives to sustain this veto as well.
The measure is presented as a means for Vermont to meet its greenhouse gas emission reduction goals by equitably reducing use of fossil fuels to heat buildings, which generates a third of the state’s emissions.
It orders the PUC to design a credit marketplace for the state’s regulated gas utility and heating fuel dealers that will help their customers pay to switch to emissions-free heating.
Scott has also expressed reservations about the cost of building electrification and the difficulty of doing it quickly. But his stated opposition to the plan is centered on its wording, which he and others read as contradictory and potentially enabling the PUC to design and enact what is essentially a carbon tax without legislative approval.
Scott criticized the legislators’ attempt add a “check back” provision to the bill that directs the PUC to report back to the legislature on its efforts to establish the Clean Heat Standard, with estimates of the impacts of the framework it draws up and any recommendations for legislative action.
“When I resisted the Legislature’s original approach to the bill, they inserted a ‘check back’ provision, saying it satisfied my concerns,” Scott said in a news release Friday. “It does not. Some claimed the bill is essentially a study. It is not. As recently as Thursday’s debate on the Senate floor, Senators from both parties have called the check back in the bill contradictory and confusing.”
Nuclear power in the U.S. is locked in a stalemate, according to a new report from the Department of Energy.
No matter how much renewable energy is deployed to decarbonize the grid, DOE is estimating that 500 to 750 GW of clean, firm power — including 200 GW of new nuclear — will be needed to reach net-zero emissions economy-wide by 2050.
“We’re going to need multiple reactor technologies to be successfully deployed at scale, from Generation 3 light water reactors to Generation 4 advanced reactors,” Kathryn Huff, who leads DOE’s Office of Nuclear Energy, told an online audience at Friday’s webinar on the recent Pathways to Commercial Liftoff: Advanced Nuclear report. Reactors of different sizes will also be needed, “from 1 MW, all the way up to gigawatt-plus reactors,” Huff said.
The report differentiates between Gen 3 and Gen 4 reactors based on the fuels they use and how they are cooled. Traditional, water-cooled Gen 3 reactors use low-enriched uranium, while Gen 4 reactors use high-assay, low-enriched uranium (HALEU) and alternative coolants such as molten salt.
“Each of these technologies has a different role to play in meeting our decarbonization goals,” Huff said. The first step to putting those 200 GW online will be “getting a committed order book of signed contracts for new reactors,” with five to 10 orders for each technology, ideally by 2025.
DOE is providing about $3.2 billion to help fund the construction of two new advanced, small modular reactors (SMRs), but the massive cost overruns and delays that have confounded Southern Co.’s Vogtle 3 and 4 reactors in Georgia have cast a long shadow over the industry, said Julie Kozeracki, a senior adviser at DOE’s Loan Program Office (LPO). (See Making the Case for Nuclear at NARUC.)
With Unit 3 just starting to produce power ― six years behind schedule and at more than twice its original $14 billion price tag ― “nuclear has a huge credibility problem to solve,” said Kozeracki, who helped author the report. “Everyone is staring at each other ― customers, suppliers, reactor designers. … Right now, every utility recognizes that they need new nuclear; they need clean, firm power. But they want to wait for someone else to go first, second, third, and order reactor No. 4 or reactor No. 5.
Launching DOE’s new report on building a strong domestic market for advanced nuclear were (clockwise from upper left) Jigar Shah, LPO; Kathryn Huff, Office of Nuclear Energy; Julie Kozeracki, LPO; David Crane, Office of Clean Energy Demonstrations, and Vanessa Chan, Office of Technology Transitions. | DOE
“But that’s not good enough,” she said. “Because if they all wait for the demo projects to be done, it’s going to be too late, and we’re going to miss the boat. … We need signed contracts, not press releases, not [memoranda of understanding] and not letters of intent, because you can’t finance a supply chain with MOUs.”
The report makes the case for nuclear as a carbon-free technology that checks a lot of boxes for grid reliability, energy security, economic development and equity, points underlined by speakers at Friday’s webinar.
“Between 2023 and 2050, about 200 electric GW of unabated coal assets are expected to retire,” Huff said. “Nuclear energy is uniquely positioned to replace those retiring assets with a similar electricity generation profile.”
“Deploying clean, firm power sources like nuclear will enable the increased deployment of renewable power,” LPO Director Jigar Shah said. “In addition to providing clean power, nuclear also uses land efficiently [and] has lower transmission requirements; so, they can site themselves on existing coal plant sites … and can leverage existing transmission infrastructure as fossil assets are retired.”
A 2022 DOE study identified close to 400 existing or retired coal plants that could be suitable for advanced nuclear development.
Huff also stressed the economic benefits of coal-to-nuclear transitions for communities affected by the closure of coal or other fossil fuel plants. “Nuclear is one of the few generation sources that can preserve the volume of high-paying jobs from those retiring coal plants,” she said. “A lot of the same people who maintain turbines and steam boilers and electricity around the plant can be rehired, and some of them don’t even need to be retrained to be leveraged into a nuclear power plant.”
The report notes that nuclear plants create about three times the number of jobs per gigawatt compared to wind projects and pay 50% more than wind or solar. Benefits for disadvantaged communities in general are also part of the picture.
“Access to reliable and resilient clean energy resources is not equitably distributed across the U.S.,” the report says. “Increasing grid reliability and resilience for underserved, overburdened communities can support improved health outcomes, public safety, economic security and overall quality of life.”
‘Megaproject Issues’
But how does nuclear compare with the low levelized cost of wind and solar, or even natural gas? It’s a question often asked by nuclear skeptics.
Kozeracki says it doesn’t matter “because of the value it’s providing for a resilient, decarbonized grid. As a clean, firm resource, nuclear doesn’t need to compete with solar by itself or with natural gas by itself. It needs to compete with solar; with really long-duration energy storage, or natural gas with carbon capture,” technologies that have yet to be proven at scale, she said.
The bigger challenge ahead is getting the orders and then completing projects “reasonably” on time and on budget, a measure the report defines as plus or minus 20%.
The report tackles the cost and time overruns at Vogtle, which Kozeracki said “were not nuclear-specific boondoggles. … They are general megaproject issues that you see with any megaproject, from building bridges to Olympic stadiums.
“The design just wasn’t complete enough before construction began, which created a cycle of rework,” she said. “There wasn’t a detailed-enough integrated project schedule or fast-enough turnaround on” quality assurance.
Nuclear is by far the most land-efficient form of power generation. | DOE
Vogtle’s workforce of 9,000 at peak also created “diseconomies of scale,” the result of trying to manage “a city’s worth of people,” Kozeracki said.
One solution for bringing down costs is a “consortium approach,” said David Crane, director of the Office of Clean Energy Demonstrations, which is overseeing the advanced nuclear demo projects. As described in the report, the strategy would allow a group of companies, such as utilities, to “enter a cost-sharing agreement for the construction of multiple reactors, likely of the same design. This pooled demand would allow for sharing risk across multiple owners and could smooth the cost curve from the first reactor to the last.”
This approach also relies on a pipeline of five to 10 projects for different types of reactors, Crane said, so that “first of a kind” does not become “one of a kind.”
“If we could get an order book going for a new wave of nuclear reactors by 2025, then I think we’ll be on our way,” Crane said. “If we don’t start until [2035] … it’s virtually impossible. Given the lead time that’s associated with nuclear, we need to be moving now.”
Crane also said “Gen 3-plus” reactors ― light-water SMRs ― could be an important first step for the industry because of the “synergies” that SMRs have with advanced reactors. Kozeracki agreed, saying that light-water SMRs are a proven technology; the Navy has been using them to power nuclear submarines since the 1950s.
“SMRs may be a bit of a ‘gateway drug’ to get us back into the habit of building new nuclear in the U.S. at scale again,” she said.
Kozeracki pointed to the example of South Korea, which has built out a successful nuclear industry by “picking one design and sticking to it and building it over and over again,” she said. The country recently set a new goal for nuclear to generate more than a third of its power by 2036, up for about 27% today, and to sell 10 reactors on the international market by 2030, according to World Nuclear News.
Supply Chains
By comparison, the U.S. has 92 reactors with a capacity of about 95 GW, a fleet that generates 20% of the nation’s power and 50% of its carbon-free power. If new reactors start coming online by 2030, with a solid supply chain, the report says, the industry could reach a steady state of growth, about 13 GW per year through 2050.
But, as Crane said, even a five-year delay on deployments to 2035 could have serious impacts, requiring an annual growth rate of 20 GW per year, which could result in an overbuilt supply chain.
The challenge here is that the U.S. nuclear supply chain is adequate for keeping the existing fleet fueled but not primed for expansion or advanced technologies. For example, the U.S. has the capacity to mine and mill ― the first steps in processing nuclear fuel ― about 2,000 metric tons of uranium per year. Getting to 200 GW will require hitting 50,000 MT per year.
Other steps in the process are equally lagging, and the country has no commercial capacity at all to produce the HALEU needed for advanced reactors. Previously, the industry depended on a single processing facility in Russia for HALEU, but because of the country’s invasion of Ukraine, companies have had to quickly look for other sources.
The difference between the low-enriched uranium used in existing reactors and HALEU is each fuel’s level of the U-235 isotope needed to sustain a nuclear chain reaction. For low-enriched uranium it is around 5%, but for HALEU, it can be up to 20%.
TerraPower, the Bill Gates-funded company that is developing one of the DOE-funded advanced reactors, announced in December a two-year delay on project completion, from 2028 to 2030, because it has not been able to procure the HALEU it needed. The company’s Natrium project is to be located in Kemmerer, Wyo., near a coal-fired plant scheduled to close in 2025.
Patrick White, project manager for the nonprofit Nuclear Innovation Alliance, said the fuel supply chain for existing reactors is “robust,” but the industry would need clear demand signals before it will be ready to invest in expansion for new light-water SMRs.
“It’s a little bit of a chicken-and-egg problem,” White said in an interview with NetZero Insider. “Uranium enrichment companies and some of the other players in the supply chain [need] a clear line of sight on what their future commercial demand is going to be [so] they know that these major capital investments are worthwhile.”
He estimated that bringing new production online would take three to five years, a time frame that could support Crane and Kozeracki’s vision for an initial buildout of Gen 3+ SMRs.
For HALEU, the challenge is less the enrichment process itself, which is similar to low-enriched fuel, but making sure “your facility is designed and licensed to produce the higher enrichment,” along with some assurance of future demand, White said.
One possibility would be for the government — in this case, DOE — to be an initial off-taker of HALEU in order to guarantee production and sales to help bring companies into the market, he said.
Other recommendations in the “Liftoff” report include low-cost federal loans to suppliers to help them build capacity for future projects, as well as public-private collaboration to create a “HALEU bank,” a stockpile to meet the needs of the demonstration projects.
DOE is actively exploring other options as well. One example is the $200 million that the department provided to X-energy to build a HALEU facility to produce fuel for its XE-100 reactor, the second project in its advanced reactor program. The XE-100 uses a specialized kind of HALEU, which X-energy will produce at a facility in Tennessee. The scheduled online date is 2025.
The department also announced in November a $150 million cost-shared award to American Centrifuge Operating to install the necessary equipment at one of its plants in Ohio to produce HALEU.
Will Utilities Take the Plunge?
Storage of spent nuclear fuel is another major obstacle. According to the report, most reactors in operation are storing their spent fuel on site while the federal government tries to find interim and permanent storage locations. Previous efforts to build a spent fuel storage facility at Yucca Mountain in Nevada were abandoned after strong opposition from the state, as well as environmental and tribal groups.
According to the report, “New legislation would be required to build a federal consolidated interim storage facility or allow development of geologic repositories for permanent disposal at sites other than Yucca Mountain.” DOE is advocating for a new “consent-based siting process” to get local buy-in before attempting to build either interim or permanent storage.
DOE defines consent-based siting as “an approach to siting facilities that focuses on the needs and concerns of people and communities. Communities participate in the siting process by working carefully through a series of phases and steps with the department (as the implementing organization). Each step and phase helps a community determine whether and how hosting a facility to manage spent nuclear fuel is aligned to the community’s goals.”
White says the industry “has a clear understanding of how to keep [spent fuel] in a safe and stable state” for on-site storage at reactors currently in operation. After spent fuel has been cooled for a year or more in cooling pools, it is stored in “dry casks,” metal or concrete-encased containers.
Similar best practices should be used for newer SMRs and advanced reactors, White said.
But both interim and long-term waste storage remain open questions. “I don’t think this is something that’s technically impossible,” White said. “But I think a lot of it is making sure that we’re incorporating both the geology, the nuclear science and the social science, and [making] sure we come up with politically feasible ideas that aren’t necessarily overburdening or unfairly putting the responsibility for managing the waste on any single community.”
Like Huff and Crane, however, White stressed the importance of building a strong order book of five to 10 projects. “The challenge is we get stuck in this process of doing one-off reactors, and we don’t necessarily get the signal that we need to build out an effective supply chain,” he said.
Some utilities are planning for those first, second and third projects. In Washington state, PacifiCorp has partnered with TerraPower on the Natrium demonstration project and recently released an integrated resource plan that included two additional Natrium reactors.
The Tennessee Valley Authority is also moving forward with plans for a GE-Hitachi SMR at its Clinch River site near Oakridge. Speaking at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in February, CEO Jeff Lyash predicted TVA could build up to 20 nuclear plants by 2050.
“I have no interest in building one reactor,” Lyash said. “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.”
Anne Pramaggiore, former ConEd CEO | © RTO Insider LLC
John Hooker, lobbyist and former ConEd executive | Chicago Housing Authority
