Xcel Energy (NASDAQ:XEL) executives told financial analysts Thursday that the recent radioactive water leak at a nuclear plant will not result in a material hit to earnings.
CEO Bob Frenzel said during the company’s quarterly conference call with analysts that the costs to repair two water leaks since last November “were not significant.” Xcel has estimated the costs to be about $2 million.
A pipe broke at Xcel’s Monticello Nuclear Generating Station last year, leading to a leak of more than 400,000 gallons of tritium-laced water. The company and state regulators did not disclose the leak until March.
Xcel patched the leak but discovered a second, smaller leak in March during a refueling outage. It has been pumping out the water and tritium from an aquifer under the plant, a process that is not expected to end until later this year or early next year.
“There was no risk to people or the plant,” Frenzel said. “It’s really about pumping water out. I expect they probably have two more weeks before they finish loading fuel and restarting the plant, but it is ready to go.”
Minneapolis-based Xcel reported first-quarter earnings Thursday of $418 million ($0.76/share), compared to $380 million ($0.70/share) over the same period last year. Earnings reflected the recovery of electric and natural gas infrastructure investments and other regulatory outcomes, partially offset by higher depreciation, operations and maintenance expenses, and interest charges.
Frenzel told analysts that Xcel continues to make progress on its clean energy transition plans. The company is reviewing proposals for 6 GW of new generation in its various jurisdictions and anticipates regulatory decisions on the proceedings in the latter half of the year.
Xcel has also submitted multiple projects to the U.S. Department of Energy for funding consideration, including hydrogen hubs in the Midwest and West, and grid resilience investments in Colorado.
The company’s share price closed at $70.26 on Thursday, a gain of 58 cents on the day.
During the same week President Joe Biden announced his re-election bid, congressional Republicans stepped up attacks on his energy agenda, with the House of Representatives passing legislation Wednesday trying to use the debt ceiling to force cuts on incentives.
Republicans from both the Senate Energy and Natural Resources Committee and the House Energy and Commerce Committee sent letters to FERC asking pointed questions about reliability, permitting and other issues as at least one of them gears up for oversight hearings. The Senate committee is holding its hearing on May 4, while the House committee has yet to schedule one.
The Limit, Save, Grow Act of 2023 cleared the House on Wednesday on a 217-215 vote, with four Republicans voting against it and no Democrats agreeing to the measure, which would raise the debt ceiling at the expense of key Biden administration priorities.
“The Limit, Save, Grow Act is a common-sense approach to return to fiscal sanity by putting an end to Democrats’ trillion-dollar spending sprees while ensuring veterans, Medicare and Social Security programs are strengthened and preserved,” House Speaker Kevin McCarthy (R-Calif.) and other members of leadership said in a statement. “It will save taxpayers trillions of dollars by reclaiming unused COVID funds, stopping Biden’s student loan giveaway to the wealthy and defunding his army of IRS agents.”
Democrats uniformly trashed the bill, with the White House releasing a statement saying that “the president has made clear this bill has no chance of becoming law” and calling on the House to raise the debt limit without strings attached. House Energy Committee Ranking Member Frank Pallone (D-N.J.) said the legislation puts polluters ahead of people.
“The bill repeals key climate provisions that Democrats delivered with the Inflation Reduction Act last year that are already making a huge difference in the clean energy transition,” Pallone said in a statement. “Since its passage, we’ve seen about $28 billion in new domestic manufacturing investments. Companies have announced $242 billion in new clean power capital investments, and more than 142,000 clean energy jobs have been created across the nation.”
FERC Oversight
Senate ENR Committee Ranking Member John Barrasso (R-Wyo.) sent a letter to FERC on Wednesday asking commissioners a number of questions about reliability and natural gas permitting. Committee Chair Joe Manchin’s (D-W.Va.) staff declined to comment on the hearing.
NERC, several ISO/RTOs and others have expressed serious concerns about the future of reliability on their grids, Barrasso said.
“You must do all that prudently may be done to enhance reliability and control electric costs for families and businesses,” he added.
Barrasso asked questions about what the impact of electrification efforts would have on reliability and affordability. He also focused on the recent report out of PJM saying about 40 GW is at risk of retirement largely because of state policies and the tight operations the RTO had near Christmas 2022. (See PJM Board Initiates Fast-Track Process to Address Reliability.)
“If electric grids suffer frequent reliability events or increasing reliability risks, doesn’t the underlying structure of the markets responsible for the grid become unjust and unreasonable under the” Federal Power Act? Barrasso asked.
The senator praised FERC’s recent approval of LNG export facilities in light of the ongoing invasion of Ukraine, but he also said the commission should get rid of the proposals pushed by former Chair Richard Glick to review the climate impacts of natural gas infrastructure.
“Both natural gas policy statements remain in draft form,” Barrasso said. “Under no circumstances should the commission attempt to finalize these policy statements in anything like their current form. They must be scrapped.”
In January the White House Council on Environmental Quality has issued an “interim GHG guidance” for federal agencies, and Barrasso asked whether and how FERC plans to apply that to its regulations.
House Energy Committee Chair Cathy McMorris Rodgers (R-Wash.) and Rep. Jeff Duncan (R-S.C.) — chair of the committee’s Energy, Climate and Grid Security Subcommittee — also wrote FERC a letter on Wednesday focusing on reliability in ISO/RTO regions. They want answers by May 10.
They pointed to rolling blackouts in CAISO, shortages in MISO and SPP, and PJM’s recent report about the 40 GW of potential retirements.
“The commission, as the federal agency responsible for the regulation of the nation’s organized wholesale electricity markets, must better understand how RTOs/ISOs have affected electric reliability,” the committee leaders said. “It is long past due for the commission to fulfill its statutory role by conducting a thorough, unbiased analysis on the reliability impacts of a policy for which it has advocated for more than 20 years.”
The letter has several questions drilling into that topic including asking for a comparison between RTOs and traditional regulation when it comes to reliability. The letter also notes that generators have not been able to secure firm gas in the markets and asks if FERC ensure that market designs allow for that.
Some Want Solar Tariffs Back
Sen. Manchin also announced this week that he was signing onto a joint resolution under the Congressional Review Act that would reimpose tariffs on solar cells from Asia, which President Biden had suspended as it led to shortages in supply. The main sponsor of S.J. Resolution 15 is Sen. Rick Scott (R-Fla.), and Manchin is the lone Democrat among nine co-sponsors.
“The United States relies on foreign nations, like China, for far too many of our energy needs, and failing to enforce our existing trade laws undermines the goals of the [Infrastructure Investment and Jobs Act] and Inflation Reduction Act to onshore our energy supply chains, including solar,” said Manchin. “I cannot fathom why the administration and Congress would consider extending that reliance any longer and am proud to join this CRA to rescind the rule.”
A similar bill cleared the House Ways and Means Committee on April 19; the Solar Energy Industries Association criticized the proposal in response.
“The United States currently lacks the capacity to produce solar panels and cells in adequate volumes to meet domestic demand,” SEIA CEO Abigail Ross Hopper said. “The two-year duty moratorium allows planned solar installations to move forward while we scale domestic manufacturing in the near term. This strategic approach protects existing jobs while new ones are added, but it also helps sustain the robust environmental, national security and job-creating benefits offered by U.S. solar deployment.”
Successful implementation of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act may hinge on Congress’ ability to put politics aside and hammer out bipartisan legislation to streamline federal permitting, Martin Durbin, senior vice president for policy at the U.S. Chamber of Commerce, said Wednesday.
States and other recipients of federal funding from those laws “are struggling to use them since lengthy permitting processes can add years and uncertainty,” Durbin told the Senate Environment and Public Works Committee during a hearing on permitting.
Inflation combined with permitting challenges is a double whammy, he said. “The longer it takes for shovels to hit the dirt, the less we’re going to be able to build.”
Durbin was one of five speakers at the EPW hearing, kicking off the search for bipartisan solutions to the permitting logjam facing clean energy and transmission projects, as well as those related to natural gas.
Sen. Shelley Moore Capito (R-W.Va.) | Senate EPW Committee
Both Committee Chair Tom Carper (D-Del.) and Ranking Member Shelley Moore Capito (R-W. Va.) stressed that a bipartisan bill passed through a “regular order” process — with committee hearings and negotiations, and broad stakeholder input — is needed to forge the needed compromises.
Carper’s must-haves for “permitting reform,” as the issue is commonly referred to, include lowering greenhouse gas emissions, maintaining “the fundamental protections provided by our nation’s bedrock environmental statutes” and supporting “early and meaningful community engagement.”
Legislation must also “provide businesses, especially clean energy businesses, with certainty and predictability and help unlock economic growth,” he said.
Capito wants a technology- and project-neutral approach with firm, enforceable deadlines for permitting and an expedited process for deciding legal challenges so projects don’t “drown in litigation.” She called for amendments not only to the National Environmental Policy Act (NEPA) but also to the Clean Water and Clean Air acts.
Permitting challenges “don’t just impact [project] sponsors,” Capito said. “They harm American workers and consumers with lost jobs, higher energy prices, traffic congestion, more pollution and many other missed opportunities that result from the failure to modernize infrastructure and energy systems. …
“If all we do is window-dress the failed system, it’s not an option. We’re not getting anywhere,” she said. “At the end of an honest negotiation, neither side will get exactly what it wants, and we all know that.”
Common Ground
While Congress remains preoccupied with raising the debt limit, bipartisan efforts to find common ground on permitting reform are underway in both houses, driven in part by the billions for clean energy projects and other infrastructure in the IIJA and IRA. The U.S. Chamber has also launched its own lobbying campaign, called Permit America to Build. (See Congress Doubling Down on Bipartisan Push for ‘Permitting Reform.’)
The EPW hearing focused on identifying both common ground and the harder-to-resolve flashpoints.
On the plus side were calls for early and robust community engagement and a close look at how to streamline permitting processes across federal agencies.
Christy Goldfuss, NRDC | Senate EPW Committee
“The U.S. must shift the value proposition around clean energy deployment and transmission and move to a model that delivers more benefits directly to communities that host this clean energy infrastructure while providing the benefits of clean energy to everyone,” said Christy Goldfuss, chief policy impact officer of the Natural Resources Defense Council. “This shift will lead to less opposition and therefore faster timelines for getting clean energy projects and transmission deployed at scale.”
Dana Johnson, senior director of strategy and federal policy at WE ACT for Environmental Justice, agreed, “We really need to start community engagement much earlier in the process … Advocates in that space noticed that when industry comes to them, when they are able to negotiate, when we have community meetings before a permitting process even begins, we are able to work in partnership to solve the challenges of bringing a project to fruition.”
The U.S. Chamber of Commerce also “fully support[s] the idea of having early engagement of affected communities with the project developers and everyone else involved,” Durbin said. “We agree that that can help to offset problems later down the road.”
Christina Hayes, ACEG | Senate EPW Committee
Streamlining processes — without changing existing statutes — also got strong support. Christina Hayes, executive director of Americans for a Clean Energy Grid, said construction of new transmission must be doubled “to have a chance at hitting our [greenhouse gas] reduction goals. …
“Specifically, high-capacity, regionally significant transmission should go through a unified federal siting and permitting authority,” Hayes said. “Bright-line thresholds for unified federal siting and permitting authority should be clearly established, which when included [with] a single point of contact for environmental review will provide for a comprehensive and legally durable siting and permitting process. …
“Additionally, developers should consider support through community benefit agreements or revenue sharing. Mitigation beats litigation every time,” she said.
Jay Timmons, CEO of the National Association of Manufacturers (NAM), also spoke in favor of “consolidated processes with enforceable deadlines for the siting of new energy projects, including hydrogen, natural gas, nuclear and other emerging technologies, along with their infrastructure.”
Programmatic environmental impact statements (PEIS) could also promote more efficient permitting, Goldfuss said. A PEIS looks at environmental impacts across a specific region, for example, the Desert Renewable Energy Conservation Plan, which sets out areas for renewable energy development on more than 10 million acres of desert lands in seven counties in Southern California.
Such an approach could allow permitting to “move toward a ‘design one, build many’ model that decouples broad swaths of the environmental review process from individual project timelines,” Goldfuss said.
NRDC also supports “Smart from the Start” planning, which means “planning and siting development in ways that minimize potential impacts and conflict before project-by-project permitting even begins,” she said.
‘Permitting Myopia’
But any change to key environmental laws — like Capito’s call for amendments to NEPA and other environmental laws — are likely to be a point of contention.
Timmons of NAM cited figures from the White House Council on Environmental Quality (CEQ) that the environmental impact statements that NEPA may require for some projects take an average of 4.5 years to complete.
Jay Timmons, NAM | Senate EPW Committee
“More time is spent just projecting potential environmental impacts than it takes to actually construct and operate a clean hydrogen power generation facility,” Timmons said. “We can and we should still set high standards for ourselves. Let’s just modernize the process [so there are] fewer delays, fewer needless losses.”
But Johnson argued that the delays and long permitting timelines attributed to NEPA are overstated, citing decade-old estimates from the Government Accountability Office that less than 1% of federal projects require a full environmental impact statement. Only 5% require a less rigorous environmental assessment and 95% receive a categorical exclusion, meaning no environmental review is required, she said.
Johnson also pointed to interconnection bottlenecks, not NEPA, as a major factor in delays for renewable energy projects. Other reasons for delays of large-scale energy projects include “poor project management, poor contracting approaches, contractors’ financial issues, delayed approvals, delayed payments, clients’ financial issues [and] challenges with the actual design of a project,” she said.
Goldfuss agreed that “permitting myopia” has put too much attention on NEPA. “Broad claims that the permitting process … is broken and that NEPA is the problem are not borne out by the facts,” she said.
Dana Johnson, WE ACT for Environmental Justice | Senate EPW Committee
Instead, she called on FERC to use its “backstop authority,” established in the IIJA, to site lines within “corridors of national interest,” which the Department of Energy must designate.
Using this authority would mean FERC could overrule state regulators and local policy makers’ decisions on such projects, something it has yet to do.
FERC must also act broadly to allocate costs for large transmission projects crossing more than one state, Goldfuss said. If not, “Congress should pass legislation requiring FERC to adopt cost allocation rules that holistically reflect the multiple benefits of transmission.”
How effective such legislation might be is uncertain given FERC’s stalled efforts to approve new transmission planning and cost allocation rules with its current membership of two Democrats and two Republicans.
Both Carper and Sen. Ed Markey also pointed to the $1 billion in IRA funding to help federal agencies hire new staff and improve their permitting processes. That money represents “a new cure,” Markey said. “Now we’re applying the medicine, and we’re waiting for it to kick in.”
The House Debt Ceiling Bill
The narrowly passed Republican bill on the debt ceiling was a tangential concern in Wednesday’s hearing.
Markey noted that the spending cuts in the bill would include the $1 billion to fund permitting improvements across federal agencies. “They want to starve the agencies and then say, ‘Look how long it takes,’” he said.
Martin Durbin, U.S. Chamber of Commerce | Senate EPW Committee
He also defended NEPA as “a safeguard for communities. We need robust, upfront community engagement to power communities with clean energy while empowering them to be part of the [process].”
Sen. Sheldon Whitehouse (D-R.I.) grilled both Durbin and Timmons on whether they would support bipartisan permitting reform crafted by the EPW Committee versus GOP permitting changes in the debt ceiling law, which would primarily push for quicker permitting for fossil fuel projects.
Timmons sidestepped the question, saying NAM was not “going to engage in picking winners and losers between House versions and Senate versions. The interest is in working on a bipartisan … proposal that will actually get done, that everyone can feel good about.”
Durbin said the Chamber had supported H.R. 1, the GOP energy bill included in the debt ceiling package. “We think it does move the ball forward,” he said, but the organization also remains “fully committed to a bipartisan process.”
The New Jersey Board of Public Utilities on Wednesday agreed to ask PJM to approve a plan for the state to undertake a second solicitation process under FERC’s State Agreement Approach (SAA), this one for grid upgrades to handle the recent increase of 3.5 GW in planned offshore wind power.
The four-member board voted unanimously to ask PJM to incorporate into its planning process the state’s goal of developing 11 GW of capacity by 2040, which Gov. Phil Murphy increased from 7.5 GW in September. (See NJ Seeks Stakeholder Input for 3rd OSW Solicitation.)
The vote came six months after the board concluded the first SAA solicitation by awarding contracts totaling $1.07 billion for transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid. FERC backed New Jersey’s plan in April 2022. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
In its latest solicitation, which it calls SAA 2.0, the board is seeking solutions for three options, according to the order approved Wednesday:
upgrading the onshore PJM regional transmission system to accommodate increased power flows from OSW facilities. This would leave OSW developers responsible for bringing power to the newly constructed onshore substations.
connecting onshore substations to offshore substations.
creating an offshore transmission “backbone” that would connect to the offshore substations.
The order recommends that the offshore cable system tie into the grid at the 500-kV Deans substation in Northern New Jersey, saying that it “is located near high electric load centers” and is accessible to the lease areas likely to service the state. In addition, PJM has in the past identified the Deans site as having the capability to handle the expected power injection.
“This process will examine whether an integrated array of open-access transmission facilities, both onshore and potentially offshore, can achieve New Jersey’s expanded offshore wind goals in an economical and timely manner,” PJM said in a statement.
The RTO said it will include New Jersey’s needs for offshore wind-related transmission improvements in a competitive proposal window tentatively set to open in 2024.
Complicated Initiatives
New Jersey officials, including BPU President Joseph Fiordaliso, have expressed concern that efforts to boost the use of electricity with wind and solar power will create a demand for interconnections that the grid can’t handle. Fiordaliso has repeatedly said he fears that the state will develop plenty of solar and OSW projects but have “no place to plug them in.”
At the same time, New Jersey is facing pushback against the rapid expansion of the OSW sector from commercial fishermen, local residents and the tourism industry, who fear a negative impact from turbines off the Jersey Shore, and from Republicans and business groups worried about the cost.
In a statement, Fiordaliso called the decision “extremely important for the future of our offshore wind program.”
During the BPU’s meeting Wednesday, he said that the approval “does not obligate the board to anything” but will initiate the kind of study necessary for such a large and complicated project.
“These are not easy decisions to make. Some of them are very complicated initiatives,” he said. “We just don’t go into these initiatives willy-nilly. There’s an awful lot of research that goes into it. How is it going to affect the ratepayer? That’s No. 1. How is it going to move us forward in achieving our goal? All of these things have to be evaluated before we say ‘yes, let’s pull the trigger.’”
PJM CEO Manu Asthana said in a statement that New Jersey has been “a pioneer in developing infrastructure needed to achieve its ambitious offshore wind policies.”
The BPU “recognized early on the value of PJM’s independent, competitive and proven transmission planning process, and we look forward to continuing to help New Jersey achieve its offshore goals reliably and as cost-effectively as possible,” Asthana said.
Jim Ferris, deputy director of the BPU’s Division of Clean Energy, said that the order only allows the board to embark on the SAA process, and any submissions would be evaluated “in concert” with PJM and not go ahead without the BPU’s approval. He added that the process includes “extensive protections for ratepayers, including cost-containment options.” Moreover, it does not preclude exploration of “opportunities for coordinating on regional offshore wind transmission up to and including a regional offshore wind backbone transmission system,” he said.
“While the second SAA is being initiated as a New Jersey-only effort, discussions with other states and federal stakeholders in this important area are continuing,” Ferris said.
Key among those discussions would likely be whether any of six successful bidders in the February 2022 auction for federal leases for OSW projects totaling 5.6 GW in New York and New Jersey would participate in a regional grid upgrade project. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
Commissioner Dianne Solomon, who has in the past expressed concern at the rising costs of New Jersey’s clean energy plans, backed the SAA proposal but encouraged BPU staff to continue looking for a regional approach to executing grid upgrades.
“We should be working as diligently in trying to get to that solution as the SAA solution,” she said. “I have no objection to doing them in tandem,” she added, urging staff to “put your pedal to metal” in pursuing a regional solution.
Reducing Costs, Risks
The board said staff “continues to believe” that the SAA process will result in “more efficient or cost-effective transmission solutions versus a non-coordinated transmission planning process.” The process also will “significantly reduce the risks of permitting and construction delays” and minimize environmental impact, it said.
The BPU picked its final contractors in the first SAA from among 80 proposals submitted by 13 developers who responded to the solicitation. At the time the board initiated the solicitation process, the state’s goal was to create 7.5 GW of capacity by 2035, and so it did not account for the extra 3.5 GW subsequently approved by Murphy.
The BPU picked only solutions to upgrade onshore transmission facilities and proposals for upgrades to resolve reliability criteria violations resulting from offshore generation injections. It did not pick any of the proposals for offshore transmission in large part because they did not result in a reduction in the number of cables, Andrea Hart, the BPU’s senior program manager for offshore wind, said at the time. The BPU instead has required applicants in the state’s third OSW solicitation to propose solutions.
BPU staff in the first solicitation selected a $504 million project that it called the Larrabee Tri-Collector Solution, which included parts of Jersey Central Power and Light’s proposal and pieces of Mid-Atlantic Offshore Development’s proposal. The BPU also approved $575 million in seven smaller projects to upgrade existing onshore transmission identified by PJM as necessary to support the OSW injections.
Ferris told the board Wednesday that the first SAA process would mean “New Jersey ratepayers will realize hundreds of millions of dollars in savings from the selection of these transmission projects, compared to the estimated cost of transmission facilities that would otherwise be necessary to achieve New Jersey’s 7,500-MW goal in the absence of the SAA solicitation.”
The U.S. Nuclear Regulatory Commission has begun a special inspection to investigate ground settling at the Davis-Besse nuclear plant in northwest Ohio, including two incidents that damaged dedicated fire-protection water lines.
The commission said Tuesday that a five-member special inspection team arrived at the power plant on Monday.
“The NRC determined a special inspection was necessary,” the commission said in a release citing that “multiple occurrences of ground settling” have occurred at the plant, including one in October and another just weeks ago that damaged the water lines. Neither settling incident occurred under the containment building holding the reactor.
The inspection team has expertise in plant fire protection, component aging, operations, geology, seismology and other geotechnical sciences, and license renewal.
Originally licensed in 1977, Davis-Besse is now licensed to operate until 2037. The 894-MW plant is owned by Akron-based Energy Harbor. A company spokesman did not return a call seeking comment.
The “special inspection team will establish a historical sequence of events related to ground-settling zones and assess the licensee’s actions to evaluate, monitor or mitigate the phenomenon and its potential impact on equipment important to safety,” the NRC said.
The team will review plant records related to ground settling, repair records related to the impacts of ground settling and geological assessments done before the plant was built, according to an NRC spokesperson, who added that the October incident was the first one affecting plant equipment of which the commission is aware.
In both cases, plant workers immediately repaired the water lines and on-site NRC inspectors reviewed their work reports. No incident reports were filed because the damaged lines were immediately repaired and did not require shutdown of the reactor.
FERC on Monday approved two SPP revisions to its tariff that would provide load-responsible entities (LREs) with an alternative short-term, nonpunitive approach to deficiency payments for their summer resource adequacy requirements (RAR).
The commission accepted the RTO’s proposal specifying that LREs making the deficiency payments will be sufficient for the current year’s RAR (ER23-1216) and a second revision that adds a deficiency payment structure applicable in certain circumstances and based on a sufficiency valuation curve (ER23-1218). The revisions are effective May 2.
Deficient LREs that make the payment are essentially buying capacity needed to make it sufficient for the current year’s RAR from other entities with excess capacity, SPP said. It would then consider those LREs sufficient for the current year’s applicable requirement.
Both revision requests were approved in January by SPP regulators, stakeholders and its Board of Directors after months of trying to reach consensus. (See SPP Board/Members Committee Briefs: Jan. 31, 2023.)
FERC said the proposed revisions are just and reasonable and not unduly discriminatory or preferential. In the first order, it said SPP’s proposal clarifies the responsibilities for both LREs that make deficiency payments, and LREs or generator owners with excess capacity that receive revenues from those payments. The latter group cannot subsequently contract to sell any of that excess capacity being paid revenue distributions to any other entity in the grid operator’s balancing authority area during the applicable summer season.
“We find that this will ensure that SPP can rely on the designated excess capacity for the SPP balancing authority area during the applicable summer season,” the commission wrote.
The RTO said in its request that without an assurance from entities receiving excess capacity revenue that they will not subsequently contract that same capacity to someone else, the BAA could see increased reliability risk if that capacity is contracted and made otherwise unavailable for serving load.
The commission also found SPP’s proposed sufficiency valuation curve to be a “reasonable method” to estimate the value of excess accredited capacity needed to resolve LRE deficient capacity in the RTO’s footprint and to calculate LREs’ deficiency payments after a planning reserve margin (PRM) increase.
FERC agreed with the SPP’s Market Monitoring Unit that this valuation of deficient and accredited capacity is “commensurate with regional resource adequacy needs, without removing the long-term planning incentive of SPP’s current deficiency payment approach.”
It said SPP’s proposed sufficiency valuation curve eligibility criteria is reasonable because it specifies the circumstances under which a deficient LRE may rely upon the methodology following a PRM increase, while ensuring that an LRE unable to meet the prior PRM is not relieved from its obligations under SPP’s deficiency payment mechanism.
SPP increased its PRM from 12% to 15% last year. It developed a mitigation strategy to address members’ concerns that they wouldn’t have enough time to meet the new requirement. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
Entergy (NYSE:ETR) told financial analysts Wednesday that it is investing to improve reliability and resilience and “significantly” expand its clean energy footprint.
“We’re working to improve operational and regulatory outcomes, support our customers’ industrial growth and economic development in our region, invest in renewable clean energy and resilience,” CEO Drew Marsh said during the company’s first quarter earnings call.
On Monday, Entergy’s leadership joined Texas Gov. Greg Abbott and four of the state’s five regulatory commissioners to break ground on the Orange County Advanced Power Station, which will use turbine technology and a plant layout that can support dual fuel capability for hydrogen in the future.
“That facility will ensure that we have moderate and reliable infrastructure to support existing customers and the rapidly growing customer base in our Southeast Texas region,” Marsh said. “The optionality helps ensure the plant’s long-term viability and creates improved energy security and operational flexibility for our customers.”
The 1.22-GW combined-cycle plant’s construction is expected to be complete in 2026. Texas regulators approved the plant last year.
Entergy reported earnings of $311 million ($1.47/share), compared to $276 million ($1.36/share) for the same period a year ago. The adjusted earnings were short of Zacks Investment Research’s projection of $1.36/share.
Entergy’s share price closed at $105.50 Wednesday, a loss of $2.26 for the day.
NextEra Beats Expectations
NextEra Energy (NYSE:NEE) reported better-than-expected results Tuesday of $2.09 billion ($1.04/share), up from 2022’s first-quarter net loss of $451 million (-$0.23/share).
The Florida-based company’s adjusted earnings of $0.84/share beat the Zacks consensus estimate of $0.75/share, the fourth straight quarter it has exceeded EPS expectations.
NextEra attributed the financial performance to a clean energy investment push that has protected it from natural gas price swings. The company says it is the first in history committed to moving past net zero to “real zero” — using only wind, solar, battery storage, nuclear, green hydrogen and other emissions-free sources.
Its NextEra Energy Resources subsidiary added more than 2 GW of new renewables and storage projects to its backlog during the first quarter, bringing the total to more than 20 GW. The company said its Florida Power & Light subsidiary increased its solar portfolio to 4.6 GW during the quarter, more than any other utility.
FPL’s recently filed 10-year site plan proposes to build nearly 20 GW of solar over the next decade.
“We believe the expansion of cost-effective solar and storage will provide a valuable hedge for our customers against volatile natural gas prices,” NextEra CFO Kirk Crews told investors.
NextEra’s stock price closed at $74.076 Wednesday after trading after hours on Monday at $79.10. The price is down 11.6% since the year began.
Global electric vehicle sales are expected to hit a record 14 million this year, up from 10 million in 2022, the International Energy Agency said Wednesday in its Global Electric Vehicle Outlook.
The EV share of the global market has grown from 4% in 2020 to 14% last year and is expected to hit 18% this year.
“Electric vehicles are one of the driving forces in the new global energy economy that is rapidly emerging, and they are bringing about a historic transformation of the car manufacturing industry worldwide,” IEA Executive Director Fatih Birol said in a statement.
The growth in EVs has significant implications for oil demand, as IEA expects they will avoid the need for 5 million barrels of oil per day by 2030. IEA reported earlier in the month that global oil demand is expected to average a record 101.9 million barrels per day this year.
China, Europe and the U.S. are the three leading markets for electric vehicles, with China being the clear front-runner, making up 60% of global sales. Europe is the second-largest market, but the U.S. grew faster last year at 55% compared to 15% in Europe.
China is home to more than half the EVs on the road, with a total of 13.8 million; the IEA credits its manufacturing dominance to more than a decade of strong policy support for early adopters. Electric cars made up 29% of China’s domestic market, beating its 2025 goal of 20% of sales. Sales spiked in China last year because incentives were winding down, but they were still 20% higher in the first quarter of this year compared to a year earlier.
Both the EU and U.S. enacted major policies expected to ramp up their industries, with IEA saying all three markets should see total sales rise to 60% of their domestic markets by 2030.
The U.S. saw EV sales increase nearly 55% to 800,000 last year despite an 8% decrease in overall new car sales. Tesla has dominated the EV market historically, but competition is coming from other manufacturers such as General Motors and Ford.
The U.S. market is expected to continue to grow thanks to the Inflation Reduction Act, which has prompted $52 billion in domestic supply chains. About half those investments are for battery manufacturing, and 20% each covers battery components and EV manufacturing.
“While these investments can be expected to lead to high growth in the years to come, the impact may only fully be seen from 2024 onwards as plants come online,” said IEA.
Policy requirements were an important driver for electrification in the early years, but IEA said it has become increasingly important for major automakers to start rolling EV models to capture market share and maintain a competitive edge.
The report said that battery manufacturing projects around the world are more than enough to meet the ramped-up production of electric vehicles by the end of the decade. Battery manufacturing remains concentrated in China, which dominates production of batteries and other components.
Lithium demand exceeded supply, despite the 180% increase in production since 2017. Battery manufacturing last year took up 60% of global lithium supply, 30% of cobalt and 10% of nickel, when just five years earlier those shares were 15%, 10% and 2%, respectively.
“As has already been seen for lithium, mining and processing of these critical minerals will need to increase rapidly to support the energy transition, not only for EVs but more broadly to keep up with the pace of demand for clean energy technologies,” the report said. “Reducing the need for critical materials will also be important for supply chain sustainability, resilience and security.”
Demand can be cut by using new battery technologies, recycling, and setting policies that optimize vehicle battery sizes, the report said.
ALBANY, N.Y. — NYISO stakeholders discussed the merits and pitfalls of the ISO’s proposed phased window approach to fundamentally rework its interconnection study processes after it was presented in greater detail during the Transmission Planning Advisory Subcommittee’s meeting April 19.
After studying how to expedite its interconnection queue, which has experienced project backlogs and delays since New York passed the Climate Leadership and Community Protection Act in 2019, NYISO recently settled on a three-stage approach that would stack a group of overlapping projects into a queue window. (See NYISO Previews Plan to Expedite Interconnection Queue.)
Stakeholders were mostly receptive but still had many concerns about the proposal, including about its timelines and scheduling; penalties for leaving the queue; and whether certain studies in one phase might be more appropriate elsewhere.
NYISO will take stakeholder feedback from last week’s meeting and address them at the subcommittee’s next meeting on May 5.
Application Review Period
Thinh Nguyen, NYISO senior manager of interconnection projects, summarized the proposal.
“The queue window leverages all the class year processes,” but instead of performing studies at the end, after developers have made significant financial commitments, “it puts all the analyses upfront to be done together so developers can make more informed decisions,” Nguyen said.
Therefore, the critical first step in the queue window would be the application review period. This “pre-act” review would serve as a “project filter,” said Nguyen, because during this time, developers would submit site-control requirements and application fees, undergo initial modeling demonstrations and create their base cases, which are the starting points for any interconnection study, showing much about a project’s feasibility.
Proposed structure of the interconnection queue window approach (*boxes not at scale*) | NYISO
The idea is to enable developers to make important decisions about whether they want to enter or exit the queue without either facing withdrawal penalties or disrupting other potential projects in the queue window. Nguyen also said that the intention of this period is to validate a certain project application’s worthiness and if it can be considered in the interconnection study.
After submitting all required application materials and a nonrefundable application fee, developers would be able to submit a study deposit if they decide they want to proceed into the queue window.
Phase 1
“Phase 1 is similar to late-stage [Class Year] optional physical feasibility studies but is a more limited clustered study, rather than the individual studies as done today,” Nguyen said.
During this period, NYISO would review project design requirements provided by developers to determine a project’s feasibility, such as if existing infrastructure can physically accommodate the project or if it has environmental issues.
This would allow developers with projects identified by NYISO as having potential feasibility issues to decide whether they want to study this issue further or if it is enough to dissuade them from moving on.
Nguyen said Phase 1 “lets developers know if they may run into some problems,” so that they can decide to either exit the queue entirely or rejoin later in another window “without delaying other projects.”
Should a developer withdraw their project in Phase 1, NYISO would refund them 80% of the study deposit, though projects that move forward to Phase 2 and then decide to withdraw would forfeit the entire deposit.
At the end of this period, NYISO would publicly publish every developer’s decision so that others can understand how a given queue window or project could be affected.
Phase 2
Projects that pass Phase 1 feasibility requirements and posted relevant deposits would enter Phase 2, which is “almost like the system impact reliability study but with a twist,” said Nguyen.
Phase 2 would create binding cost estimates that are based on identified equipment and work upgrades necessary to interconnect a proposed project, which is unlike current processes that produce a nonbinding cost estimate.
Nguyen said Phase 2 is “tailored” to gives developers a “heads-up about some of their potential system upgrades that would be beyond the POI [point of interconnection].”
“This could be a step where we can streamline a lot of processes that we have today,” he said.
During Phase 2 the queue’s base cases would also be updated to reflect projects that were either rejected or withdrew during Phase 1 and the ISO performs limited analyses, such as short circuit, localized stability and screening deliverability analyses to generate useful information that reduces Phase 3 study times.
Developers who accept Phase 2’s results and project binding cost estimates would be required to post a project’s dollars-per-megawatt cash deposit before moving to Phase 3. Projects withdrawn during Phase 3 would see 25% of the cash deposit forfeited.
Like Phase 1, project decisions made in Phase 2 would be posted publicly by NYISO.
Phase 3
“Phase 3 is basically the final study for developers to know the certainty of their cost allocations,” Nguyen said.
During Phase 3, NYISO would update relevant base cases to reflect any projects that withdrew and perform any additional analyses needed to determine a project’s final cost allocation based on potential upgrades identified by the ISO.
Doreen Saia, an attorney with Greenberg Traurig, sought clarification, asking whether “Phase 3 is essentially becoming an additional deliverability study and additional SUF [system upgrade facility] study,” which Nguyen confirmed as correct.
Nguyen explained that the structure of NYISO’s proposal intentionally stacks projects together into a single queue window and staggers their study processes to “minimize the potential restudy or interaction between projects as much as possible.” This means, for example, a project might not commence Phase 3 studies until another project finishes its processes in the same window.
“The idea is that subsequent queue window projects will be able to consider upgrades identified in prior queue window projects,” which makes the queue “more manageable, because subsequent projects will know exactly who the group of projects prior to them are and what decisions they have to make,” he said.
Nguyen said that NYISO’s proposed “concept is much better than what we have today because when we studied projects individually, they had no idea what going on with other Class Year members … creating more uncertainty for those project developers.”
A developer who accepts their Phase 3 cost allocations would be required to post security for any system deliverability or facility upgrades necessary for interconnection to complete the queue window study process.
The Phase 3 decision-making period, like the end of the Class Year process, would be an iterative process that repeats until every queue window project member either accepts or rejects their cost allocations.
Stakeholder Comments
Stakeholders shared many concerns, both specific and general, about NYISO’s proposed revisions during last week’s meeting.
Several stakeholders commented that the proposed penalties incurred by developers withdrawing from the queue window may be overly burdensome, prohibitive and unequal, as bigger projects may be susceptible to higher fines than smaller ones. Some singled out the 20% for a Phase 1 departure as too high.
NYISO attorney Sara Keegan, however, said the amount is “consistent with other ISOs,” with SPP taking 20% from projects leaving at the end of its Phase 1 study. Nguyen said this is “a penalty that deters projects that are just not ready yet.”
Mark Reeder, representing the Alliance for Clean Energy New York, concurred, saying how he saw the 20% forfeiture “as the penalty for those starting and not being ready,” which to him seemed good because “we don’t want a lot of people jumping in and then out [of the queue] without a good reason.”
Vitaly Spitsa of Consolidated Edison asked what deliverables would come out of Phase 2 and whether, by this point in the process, developers would have access to sufficient information to make critical decisions about moving ahead in the queue.
Nguyen said that by the end of Phase 2, “developers will know exactly what the potential cost is of their binding POI” and about any necessary upgrades, which “definitely isn’t all the information but is sufficient information for a developer to make a decision about whether they want to move to the next phase.”
Anthony Abate, lead energy market adviser with the New York Power Authority, said NYISO’s illustrations of its queue window were “deceptively simple” and that “the devil’s in the details,” referencing how lengthy discussions during the meeting show that stakeholders need more information about the structure and timeline of the proposal.
Although much of the meeting was spent answering stakeholder questions or addressing comments of concern, some attendees expressed optimism about the ISO’s proposal.
Shane O’Brien, senior director with Aypa Power, said “from the developer’s side, this is a step in the right direction,” because NYISO’s proposal addresses “administrative inefficiencies” and “those downtime wait periods” where developers may be waiting for others before they can make their own decisions.
However, a remark by Saia seemed to best capture the sentiment among the stakeholders present at the meeting.
In reference to how NYISO’s proposal would remove much of the Class Year studies, such as the system impact reliability study or siting and permitting processes, Saia said, “We must make sure that whatever we do in this new process, [former] processes align, because if they don’t, then it’s great that you fixed this, but it’s going to create discordance somewhere else that causes the whole thing to die under its own weight.
“NYISO needs to indicate that you acknowledge and recognize [these concerns] because I don’t think you’re going to be able to get any real signoff on this without those assurances,” she said.
EPA is reportedly poised to propose rules that would require all coal and gas-fired power plants to reduce or capture nearly all of their carbon dioxide emissions by 2040.
The New York Timesreported Saturday that EPA plans to release a rule that for the first time would set limits on carbon dioxide emissions from existing power plants.
The pollution limits would not be technology specific, allowing natural gas plants to either capture their carbon, or switch to “green” hydrogen that is produced without carbon emissions, according a report in the Times that was largely confirmed by The Washington Post.
While carbon capture has proven expensive on power plants, recent federal legislation, including the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, have set up a comprehensive framework that should enable the wide-scale deployment of carbon capture by 2030, the Carbon Capture Coalition said Monday in releasing its 2023 Federal Policy Blueprint.
The IRA increased federal tax credits for electric utilities that capture their carbon dioxide from $30 to $50/ton of CO2 to $85 to $135.
At a press event announcing the blueprint Monday, the coalition’s Executive Director Jessie Stolark said its wide-ranging membership has not had a chance to coordinate a response to the reported regulations yet. The group has focused mainly on market-incentives to encourage carbon capture technology, she added.
“I really want to underscore that our members agree that deploying carbon capture technologies in the power sector is absolutely critical to reducing emissions, as well as providing a more affordable, reliable baseload power and a deeply decarbonized energy grid,” Stolark said.
Shannon Heyck-Williams, vice president of climate and energy for the National Wildlife Fund, who participated in the coalition event, said her group welcomed news of EPA’s plans.
“WF is very excited to see this rule come out,” she said, saying CCS technology could have a role to play with some natural gas plants. “Obviously, we can’t adequately tackle climate change unless we’re really dramatically reducing power sector CO2 emissions. And, frankly, we could get to zero. That’s the goal.”
In response to EPA’s request last year for comments on how it should handle emissions from “electric generating units,” the Edison Electric Institute spelled out a way that it said could encourage cuts without mandating specific technologies.
EEI noted that for now the main way to cut emissions from power plants is to make them more efficient, with both hydrogen and carbon capture technologies not quite ready for mass deployment.
“Both hydrogen co-firing and CCS technology face a number of other challenges that will need to be overcome to enable commercial scale use throughout the industry,” EEI said. “Government and industry are investing in addressing these cost, technology, and infrastructure challenges. With that investment, there is reason to be optimistic that these challenges will be overcome in this decade.”
EEI argued that any new rules should be flexible, saying that hydrogen and carbon capture might work in some regions of the country but be infeasible in others. The agency should allow new power plants to retrofit those technologies when they become viable.
EEI also suggested that the agency would benefit from shifting to mass-based tonnage requirements for regulated units. Previous emissions rules have used a rate-based system.
“Since decreases in (or limits of) a unit’s capacity factor have a direct impact on its CO2 emissions profile, states, EPA, and units can employ a mass-based approach to leverage the emissions reductions benefits of a decrease in capacity factors, while preserving maximum operational flexibility to support overall system reliability by preserving the availability of units for resource adequacy, particularly during extreme weather events or other emergency conditions,” EEI said.
“We’ve got to go with a scale, we’ve got to go with the pace like never before,” U.S. Deputy Secretary of Energy David Turk said at the coalition’s webinar Monday. “My former colleagues at the [International Energy Agency] projected that by 2030, we’ll need to lock away roughly 30 times as much carbon as we’re currently managing, and nearly quintuple that by the middle of the century.”
DOE has made $10 billion available for a suite of carbon management applications, including the recent request for six demonstration projects at coal and natural gas plants, he added. DOE is also working with the Treasury Department to finalize the expanded 45 Q tax credit for carbon capture, said Turk.
EPA’s power plant rules would not be finalized until next year, following a public comment period. The Biden administration hopes to complete the regulations before Republicans could upend them by winning control of Congress in 2024. The Congressional Review Act allows a new Congress to reject regulations finalized within 60 days of the previous Congress.
The administration also is attempting to craft the rules to withstand certain court challenges.
The Supreme Court ruled last June that the Obama administration’s EPA failed to provide “clear congressional authorization” for its Clean Power Plan, which would have compelled generation shifting to reduce carbon emissions from coal-fired power plants. (See Supreme Court Rejects EPA Generation Shifting.)
