California Gov. Gavin Newsom signed major legislation Thursday that would expedite permitting for new generation and storage facilities and potentially extend the life of aging gas plants and the state’s last nuclear power plant in an effort to maintain grid reliability during the coming summers.
Assembly Bill 205 and Senate Bill 122, introduced as placeholder measures in January, were rewritten and published as omnibus energy budget trailer bills on Sunday, with only a few days for public review. The State Legislature passed AB 205 on Wednesday night and sent it to Newsom to sign. Lawmakers voted on the Senate version Thursday and submitted it to the governor. Both bills will take effect at the start of the new fiscal year Friday.
The measures approved Newsom’s proposed $5.2 billion strategic reliability reserve consisting of “existing generation capacity that was scheduled to retire, new generation, new storage projects, clean backup generation projects, [and] diesel and natural gas backup generation projects.” (See Calif. Governor Proposes $5B ‘Reliability Reserve’.)
They also make the Department of Water Resources the backstop procurement agency for short- and mid-term reliability needs. That could mean purchasing energy from Pacific Gas and Electric’s Diablo Canyon nuclear power plant, scheduled to retire in 2025, and a fleet of aging natural gas plants along the California coast. The once-through cooling plants had been scheduled to retire in 2020 because of their destruction of ocean life, but the state extended their lifespans to 2023 for grid reliability. (See OTC Plants to Remain Open, Calif. Water Board Rules.)
Continued reliance on the plants could extend their lifespans beyond the retirement dates, critics of the trailer bills said. The U.S. Department of Energy retains authority over Diablo Canyon, but Newsom’s office has petitioned it for a share of federal funds to keep the plant operating, and the bills would set aside $75 million toward that goal.
The measures also enact sweeping changes to approvals of new energy projects by creating an “opt-in” process to allow the California Energy Commission (CEC) to consolidate permitting, including for larger solar arrays and battery installations, while mostly bypassing other federal, state and local permitting processes. The typically laborious review under the California Environmental Quality Act will also be streamlined.
In a joint statement, environmental groups urged lawmakers to take more time to fix the bills, which they said give “unprecedented new authority and a blanket exemption for the Department of Water Resources to finance, construct and/or operate any type of energy project without compliance with existing local, state or federal laws.”
The Nature Conservancy, Sierra Club and two dozen other groups also protested the creation of a new approval process at the CEC that “completely overrides the jurisdiction” of state, regional and local planning authorities.
During Wednesday night’s floor debate, Democratic lawmakers, including some staunch environmentalists, defended the bills as necessary for maintaining reliability over the next several years as the state transitions toward 100% clean energy.
“We’ve looked at the data, and we realize that we’re going to have or may have a shortfall,” State Sen. BobWieckowski (D) said. “It may happen this summer. It may happen in 2023, 2024 [or] 2025. … It may mean in order to keep the lights on [for the residents] of California, we may have to procure some of these dirty fossil fuels.”
After energy emergencies the past two summers, including rolling blackouts in August 2020, the state has struggled to bolster capacity to meet peak demand. Extreme heat, drought and wildfires have made that difficult, and state energy planners have said the state could face more shortfalls during the next four summers of 1,700 to 10,000 MW, depending on the severity of circumstances. (See Heat, Fire and Supply Chain Woes Threaten Calif. Reliability.)
Lawmakers previously accepted Newsom’s broad energy plan in principle but left spending details to be worked out in closed-door negotiations between the governor’s office and legislative leaders in recent weeks. (See Calif. Lawmakers Offer Alternative Energy Budget.) The result was the language in the budget trailer bills approved Thursday.
Balancing authorities in three of the four Midwest Reliability Organization subregions are likely to face capacity shortfalls this summer requiring external energy assistance or other emergency measures, the regional entity warned in its Regional Summer Assessment.
MRO conducts its regional assessment each year as a complement to NERC’s Summer Reliability Assessment and to identify potential issues on a “more granular” level, MRO Principal Reliability Assessments Engineer Salva Andiappan said in a webinar on Thursday. The RE’s assessments also analyze historical data from previous summers to spot trends that could impact grid reliability in coming seasons.
MRO’s summer forecast includes the months of June through September. Like NERC’s summer assessment, released in May, MRO warned that SPP and Saskatchewan Power are both at elevated risk of energy emergencies, while the MISO North and Central areas are at high risk. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.) Only Manitoba Hydro indicated it possesses sufficient resources to meet the subregion’s reserve margin requirements under both normal and extreme demand scenarios.
Highest Risk for MISO North, Central
The normal demand scenario, also called the 50/50 scenario, represents a prediction with a 50% chance of being exceeded, while the extreme scenario, also called 90/10, has a 10% chance of being exceeded. Under the first, MISO, SPC and SPP anticipate reserve margins of 3.2%, 2.6% and 12.3% respectively, well below the requirements of 17.9%, 11% and 16%.
Under extreme conditions, the margins for all three drop below zero, leading to a high risk that the BAs will have to issue energy emergency alerts and implement operating mitigations including non-firm imports, demand response and short-term load interruption, a likelihood that is low for Manitoba Hydro in both conditions.
MISO’s projection is based on results of the RTO’s recent Planning Resource Auction, which MRO said indicated “insufficient capacity to cover anticipated summer peak demand and increased risk of needing to implement temporary, controlled load sheds” under extreme conditions. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) The RTO’s shortfall of more than 1.2 GW was caused by increased load forecast coupled with retirements of existing generation resources and their replacement with new resources with lower capacity.
MRO 2022 summer peak capacity by fuel types | MRO
One bright spot in this forecast is that some units that “did not qualify for reserve capacity in the PRA” might still be able to help MISO serve energy during the summer. However, MRO still said the shortfall in the month of July could reach as high as 5 GW.
SaskPower, meanwhile, is expected to strain under a 7.5% increase in peak demand driven by “the economy returning to pre-pandemic levels” as well as oil and gas development. The subregion should be able to meet normal demand but may need “external assistance” in conditions of above-normal generator outages; this is also the case for SPP, where the elevated risk is attributed to drought conditions affecting water sources needed for generation and cooling.
For Manitoba Hydro, on the other hand, the scenario is quite rosy; the subregion reported it anticipates no unexpected rises in load, unlike last summer, while new generating units coming online at the Keeyask hydroelectric station are expected to expand the margin comfortably. The fifth and sixth units are expected to enter service this summer, and the last should be online by winter, MRO said.
A new hydrogen task force set to launch in July could provide Connecticut legislators with the information they need to create “a very robust hydrogen package” in the next legislative session, Rep. David Arconti (D) said Wednesday.
Connecticut Gov. Ned Lamont signed a bill in May authorizing the creation of a task force responsible for creating a hydrogen study and delivering it to the General Assembly by Jan. 15.
Brian Garcia, president of the Connecticut Green Bank, will chair the 21-member task force, which must hold its first meeting by July 22, as directed by the legislation (SA22-8).
Passage of the Infrastructure Investment and Jobs Act (IIJA), which includes $8 billion in federal matching funds for a federal hydrogen hubs program, gave the hydrogen study bill “more momentum” during the session, Arconti said at a legislative and regulatory update hosted by the Connecticut Power and Energy Society. A March agreement among Connecticut, New York, Massachusetts and New Jersey to submit a regional proposal for the hub program made the study bill “even more timely,” he said.
“A lot of people in the legislature are excited to talk about something that could decarbonize a lot of sectors, and they are racking their brains around how we can get to net-zero [electricity] by 2040,” he said.
The study of hydrogen-fueled energy in the state’s economy and infrastructure will include reviews of:
regulations and legislation to achieve economies of scale for hydrogen;
hydrogen-related incentives and programs in IIJA;
workforce development opportunities;
sources of clean hydrogen, including wind, solar, biogas and nuclear; and
funding sources for hydrogen energy programs and infrastructure.
Waste Solutions
A new state working group is gearing up to begin a separate study to identify waste disposal solutions following the planned shutdown this summer of the Materials Innovation and Recycling Authority (MIRA) waste-to-energy plant.
Lamont signed legislation (SA22-11) in May authorizing the working group, which Sen. Norm Needleman (D) will co-chair. The working group does not have a legislatively mandated start date, but it must submit the study to the legislature by Jan. 1.
Without the MIRA plant, Connecticut will ship “large amounts of solid waste to other states, in many cases to environmental justice communities,” Needleman said during the CPES webinar. “With the emissions that will cause, from trucks and trains as well as burying the [waste], we’re going to get the methane one way or the other.”
The MIRA plant, which is one of five waste-to-energy facilities in the state, has been operating since the late 1980s. The high cost of redeveloping the facility led to the planned suspension of waste combustion. MIRA instead asked regulators last September to amend its permit to allow for the transfer of 275,000 tons of waste per year to other licensed management facilities.
Needleman hopes the working group will produce ideas for new waste management legislation.
“I want … another 20-year solution that puts us back on the right track to reducing waste and converting whatever we can to energy, either by anaerobic digestion or by burning what’s left in a more efficient burn plant,” he said.
There is potential for expanding the state’s existing waste-to-energy capacity or building another plant that Needleman expects would provide “a lot of benefits.”
“We’re taking a step back on the short-term basis,” he said, adding that he expects the state will still “get to a point where we have solutions all the way around.”
Reactions to the Supreme Court’s decision in West Virginia v. EPA came fast and, predictably, framed with an eye on upcoming midterm elections.
The 6-3 decision overturned a lower court ruling that had upheld the EPA’s authority to regulate carbon emissions from existing power plants under the Clean Power Plan developed during the administration of former President Obama and overturned by his successor, former President Trump. (See Supreme Court Rejects EPA Generation Shifting).
“Capping carbon dioxide emissions at a level that will force a nationwide transition away from the use of coal to generate electricity may be a sensible ‘solution to the crisis of the day,’” said Chief Justice John Roberts, writing for the majority. “But it is not plausible that Congress gave EPA the authority to adopt on its own such a regulatory scheme in Section 111(d) [of the Clean Air Act]. A decision of such magnitude and consequence rests with Congress itself, or an agency acting pursuant to a clear delegation from that representative body.”
Republicans and fossil fuel industry groups praised the court, decried the Biden administration’s regulatory “overreach” and linked federal efforts to cut greenhouse gas emissions to high gas prices and the threat of summer power outages.
Democrats and clean energy advocates meanwhile criticized the court for its backward-looking decision and called for federal and state legislative action in response.
But on Twitter, and among legal and energy experts, the reactions were more measured, seeing the decision as a curb on EPA authority but far from gutting its ability to regulate greenhouse gas emissions under the Clean Air Act.
For many, the question is how the decision will affect President Joe Biden’s goal of cutting greenhouse gas emissions 50% by 2030, the U.S. commitment under the Paris climate accords.
John Bistline, a program manager at the Electric Power Research Institute, said reaching that goal will mean policies will have to evolve. Bistline said the country still has “a lot of ways we could potentially reach those targets that could be combinations of federal and state policies, things like a CO2 cap-and-trade system … regulation like performance standards, including the ones that were at the center of today’s decision, as well as broader incentives, things like enhanced tax credits.”
But Bistline also said the decision could create uncertainty for utilities and other businesses. Based on existing policies, the U.S. will only be able to cut GHG emissions 6% to 28% below 2005 levels by 2030, he said.
The Governors
West Virginia Gov. Jim Justice (R) was among the first to weigh in on the decision. “This ruling … will stop unelected bureaucrats in Washington, D.C., from being able to unilaterally decarbonize our economy just because they feel like it,” Justice said. “Instead, members of Congress who have been duly elected to represent the will of the people across all of America will be allowed to have a rightful say when it comes to balancing our desire for a clean environment with our need for energy and the security it provides us.”
West Virginia Gov. Jim Justice | Office of Gov. Jim Justice
Texas Gov. Greg Abbott (R) called the ruling a “landmark victory against an out-of-control administration” and “a big win for Americans who worry about skyrocketing energy costs due to expensive federal regulations that threaten our energy industry.” Texas and West Virginia were among 20 states that joined in the court challenge.
But California Gov. Gavin Newsom (D) slammed the court for siding “with the fossil fuel industry [and] kneecapping the federal government’s basic ability to tackle climate change. Today’s ruling makes it even more imperative that California and other states succeed in our efforts to combat the climate crisis. While the court has once again turned back the clock, California refuses to go backward — we’re just getting started.”
Washington Gov. Jay Inslee (D) agreed in a Twitter post, saying the court had “dealt a blow to federal efforts to combat [the] climate change ravages of coal fired pollution. This means we, in our own state, need to up our game. We are fully up to the task. States like [Washington] have been leading on climate action, and we aren’t done.”
Capitol Hill
Congressional leaders on both sides of the aisle declared themselves ready to use their legislative authority, although with very different goals in mind.
Rep. Cathy McMorris Rodgers (R-Wash.) | House E&C Committee
“When Congress acts to address major policy questions affecting Americans and their livelihoods, it says so clearly, explicitly,” said Cathy McMorris Rodgers (R-Wash.), ranking member of the House Energy and Commerce Committee.
“It does not hide sweeping authorities of the executive branch in obscure provisions of the law … This decision restores power to the people through their elected representatives.”
Sen. John Barrasso (R-Wyo.), ranking member of the Senate Energy and Natural Resources Committee, tweeted that the decision “rightfully reins in unreasonable and unlawful attempts to shut down American power plants and energy production.”
In response, longtime climate advocate Sen. Ed Markey (D-Mass.) said the decision “takes away the EPA’s firehose and gives it a leaky bucket instead.
Sen. Ed Markey | Sen. Ed Markey via Twitter
“We will fight in Congress and in the executive branch to do what we can and to not back down, but no one, not ISO-NE, not our state governments, not our city councils, can now sit out this crisis and wait for a climate chaos to arrive,” Markey said at a Thursday press conference. “The Supreme Court will not and cannot be the last word on climate action.”
“There is no doubt that this decision is the result of years of coordinated, calculated efforts by Republicans and polluting special interests to undermine Americans’ right to clean, safe air,” said Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee.
He called on Congress to “redouble our efforts to enact robust climate programs and investments to address the crisis we face. EPA continues to have many powerful tools at its disposal, and there is more both Congress and the president can do to meet the climate crisis head-on.”
The Lawyers and Academics
Discussions on Twitter focused on the decision’s “silver linings” and other pathways to GHG emissions reductions.
The court “did NOT go after EPA’s authority to regulate GHGs,” said Jesse Jenkins, a professor at Princeton University’s Andlinger Center for Energy and Environment. “They just struck at the Obama EPA’s outside fence line sectoral approach to regulate emissions under 111(d), which was always a ‘creative’ reading of statute, if we’re being generous.”
Jody Freeman, director of the Environmental and Energy Law Program at Harvard Law School, agreed, saying the decision does not strip the EPA of its authority. “The silver lining is EPA’s authority to determine [the] best system of emissions reduction is intact and reinforced,” she said.
Similarly, Michael Gerrard, director of the Sabin Center for Climate Change Law at Columbia University, said EPA can still regulate GHG emissions from motor vehicles and new power plants and factories. “The decision was basically about coal-fired power plants, but EPA can still regulate them in other ways, such as limiting their other air pollutants; coal ash; hot water discharges.”
Trade Associations
Reactions from utility and fossil fuel trade associations supported the decision but were more moderate in tone and keyed to reflect consumer concerns.
Jim Matheson, NRECA | NRECA
Jim Matheson, CEO of the National Rural Electric Cooperative Association, said the decision puts the EPA back on an “appropriate regulatory path, requiring it to set achievable emissions guidelines that can be accomplished at existing power plants, while also allowing states to consider local factors and have the final say on compliance options.
“The energy decisions we make today will determine whether there are sufficient resources for the lights to come on tomorrow,” Matheson said, linking early “disorderly” fossil fuel plant retirements to the threat of rolling blackouts through the summer months.
Michelle Bloodworth, CEO of America’s Power, a coal industry trade association, echoed Matheson.
Michelle Bloodworth, America’s Power | USEA
“We urge EPA to avoid issuing a replacement rule that causes more premature coal retirements, especially as officials are warning about the prospect of electricity shortages that threaten grid reliability in many parts of the country.”
While not directly commenting on the decision, the American Petroleum Institute (API), touted the industry’s efforts to reduce its emissions, through “continuous innovation.”
The industry has already reduced its CO2 emissions to “generational lows … outpacing the Clean Power Plan,” and “will continue to work with policymakers across the federal government in support of smart regulations that build on the progress we’ve made on CO2 emissions reductions while bolstering our energy security,” API said.
The Advocates
Advocacy groups focused on the ripple effects the decision could have.
Sasha Mackler, executive director of the energy program at the Bipartisan Policy Center, said the ruling will cause uncertainty at a time “when greater clarity on national climate policy is needed.”
“Administrative actions to reduce carbon emissions are important, but they have proven to be slow, contentious and inadequate,” Mackler said. “With agencies now further constrained, the only path forward to a broad and effective program driving the transition to a national low-carbon energy system is for Congress to come together to enact durable, bipartisan energy and climate legislation.”
Drew Bond, president of the Conservative Coalition for Climate Solutions, called the decision “a win for the climate and constitutional democracy.
“Innovation, not overregulation, is the solution to reducing global greenhouse gas emissions,” Bond said. “Instead of looking to regulators to impose top-down mandates, activists on all sides should ask legislators to pass laws that encourage bottom-up solutions.”
But Andrew Behar, CEO of As You Sow, a shareholder advocacy group, said the decision could put a damper on corporate commitments to reduce emissions “and will leave the U.S. economy behind Europe, China and other nations driving low-carbon technology development.
“Investors with trillions of assets under management are moving to decarbonize their portfolios to achieve net-zero emissions and thousands of the world’s largest companies, many in the S&P 500, are setting targets for their operations and value chains to draw down their emissions to net-zero,” he said. “An even playing field and clear regulatory guidelines from EPA are necessary to drive progress across the economy.”
With the electric sector facing shortages of critical spare parts and supplies, and another active hurricane season looming, industry stakeholders at all levels must work together to keep the grid functioning, participants in a webinar hosted by the U.S. Energy Association said Wednesday.
The supply of critical equipment, particularly transformers, has been a growing concern because of supply chain disruptions amid the Russo-Ukraine conflict and the ongoing COVID-19 pandemic. Earlier this month, President Joe Biden invoked the Defense Production Act to “accelerate domestic production of” several types of energy equipment including “transformers and electric grid equipment,” along with insulation and solar panels.
Biden’s decision followed a joint letter sent last month to Energy Secretary Jennifer Granholm by the National Rural Electric Cooperative Association and American Public Power Association (APPA) urging the Department of Energy to temporarily waive energy conservation standards for distribution transformers in order to allow manufacturers to speed up production.
Joy Ditto, APPA | USEA
APPA CEO Joy Ditto, who cosigned that letter, said in Wednesday’s webinar that the organizations are still pushing the government to waive those standards and commit to a moratorium on “new efficiency standards coming down the pike in at least the short- to medium-term.” She warned that while electric sector participants are doing what they can to ease the supply chain burden, the manufacturing sector remains a missing piece of the puzzle.
“We’re asking for our members to do their part, and the sector to do its part, to share with each other … [and] we’ve had some good success with that already,” Ditto said. “But in terms of the longer-term view, we are going to need to really get a handle from the manufacturers about how this can be alleviated.”
Attendees at the webinar said supply chain choke points are already emerging, creating grave concerns with summer just beginning and NERC warning of another active wildfire season in the Western U.S. and Canada. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.) Rudy Garza, interim CEO at San Antonio’s municipally owned gas and electric utility CPS Energy, said his company was “probably managing [the situation] as well, if not better than most utilities in our sector” by diversifying its supplier base to avoid tapping out any one supply line.
No Time Like the Present
But CPS is still having difficulties obtaining equipment and has had to postpone both work on existing projects and getting new projects underway. Rising costs are also creating problems for the utility.
Ray Kowalik, Burns & McDonnel | USEA
“We’re seeing delays on our bread-and-butter equipment, from standard transformers [for] residential subdivisions, to … gas risers,” Garza said. “I was at our gas facility the other day waiting on a truck to come in, and that truck was delayed … to January of next year. And so my team is trying to figure out how we’re going to manufacture what we need to be able to make those gas connections and go talk to our regulator to make sure that they approve it.”
Asked whether these issues might open the door for new suppliers of electric equipment to address the bottlenecks, attendees agreed that the problem is not that simple. Garza said that he would “love to be able to go to Amazon and order a transformer, but you still have to have a manufacturer on the other side,” to which Ray Kowalik, CEO of Burns & McDonnell, pointed out that distribution issues are relatively easy to solve.
“Quite honestly, the delivery problem can generally be fixed with money,” Kowalik said. “You can pay a little more to get … the trucking company to get your product there. But fundamentally the problem is making enough product and getting it out of the facilities and to the end users.”
Scott Aaronson, EEI | USEA
However, attendees did see an opportunity in the current situation to address other ongoing issues with the electric equipment supply chain. Scott Aaronson, a senior vice president for security and preparedness at Edison Electric Institute, said that simplifying and standardizing production lines might not help utilities iron out their current delays any faster, but they might help enormously the next time manufacturing and distribution lines are squeezed.
“If you look across just distribution transformers, for example, I learned recently there’s more than 10,000 [stock keeping units] for distribution transformers across the United States. That’s absurd,” Aaronson said. “Now, the best time to plant a tree was 20 years ago, [but] the second best time is today. And so … starting to tack toward a more standardized system at the distribution level so that we can more efficiently share material and equipment … can help break down some of the supply chain challenges we’re seeing now.”
FERC on Tuesday approved SPP tariff revisions that establish an annual process for each transmission pricing zone to develop a single set of uniform zonal planning criteria used to evaluate zonal reliability upgrades in the RTO’s regional transmission planning process. The changes became effective Wednesday (ER22-1719).
The commission found the proposed process allows for the “collaborative development” of zonal planning criteria in multi-transmission owner zones that will then be used to determine the need for zonal reliability upgrades. It said SPP’s proposal is just and reasonable as it would address concerns over the current process, which could lead to confusion and potential inequities because zones with multiple TOs can have multiple sets of local planning criteria for the same zone.
SPP’s transmission pricing zones | SPP
FERC’s approval came after it rejected SPP’s first attempt to change the zonal planning criteria in 2020. The commission sided with stakeholders’ argument that the proposal would have given a pricing zone’s lead TO “unilateral power” and “unduly” benefit them and the zone’s largest network load customer. (See FERC Rejects SPP’s Zonal Planning Criteria.)
The commission said SPP’s revised proposal addressed its concern because it establishes a defined process by which a zone’s TOs and transmission customers can provide input on potential planning criteria, and comment and ultimately vote on draft criteria developed by the facilitating transmission owner (FTO).
“SPP’s proposed zonal planning criteria process provides for meaningful opportunities for input from interested stakeholders,” FERC said.
The RTO has 18 transmission pricing zones, 10 with multiple TOs. The revised proposal designates an FTO responsible for facilitating that zone’s development of a single set of planning criteria for that zone. SPP has recommended that the network customer with the zone’s largest total network load be the FTO.
A zone’s TOs and customers that receive long-term service can submit proposed planning criteria to the FTO by May 1 each year. The FTO will have until June 1 to post its draft criteria, and all interested parties will then have 30 days to respond with written comments. The FTO must hold at least one open meeting each year and conduct a two-step voting process that includes a load-weighted vote of all transmission customers receiving service to approve the final criteria.
FERC’s approval culminates a process that began in 2018 with SPP’s Holistic Integrated Tariff Team. The stakeholder group made 21 recommendations that included the zonal planning criteria. (See SPP Board Approves HITT’s Recommendations.)
The RTO’s filing at FERC drew nearly two dozen intervenors, as well as protests from Oklahoma Gas & Electric, GridLiance High Plains and a group comprising Evergy’s affiliates and ITC Great Plains. The commission disagreed with their arguments that SPP was replacing zonal planning with its regional planning process and violating FERC Order 1000’s requirements, and that the proposed two-step voting mechanism is inequitable because either the FTO or a small transmission customer can effectively veto the criteria’s adoption.
The Supreme Court on Thursday ruled 6-3 that EPA lacks authority to compel generation shifting to reduce carbon emissions, saying the agency failed to provide “clear congressional authorization” for the rulemaking (West Virginia, et al. v. EPA, et al.).
The immediate impact of the court’s ruling is minimal: It voided the Obama-era Clean Power Plan, which was withdrawn by the Trump administration, and the Biden administration has said it would not attempt to implement it.
But as the latest in a series of orders by the conservative-dominated court to limit executive agencies’ discretion, it could act as a constraint on any future EPA action. The Biden administration told the court in oral arguments in February that it planned to issue a replacement for the CPP by the end of this year. (See Supreme Court Hears Arguments on EPA Authority over GHGs.)
President Biden called the ruling “another devastating decision that aims to take our country backwards.” He said he has directed officials to review the decision “and find ways that we can, under federal law, continue protecting Americans from … pollution that causes climate change.”
The CPP sought to cut power sector carbon emissions by 32% compared with 2005 levels by 2030 by substituting coal-fired generation with natural gas and renewables. EPA said it was permitted under Section 111(d) of the Clean Air Act, which empowers it to impose standards “for any existing source” based on limits “achievable through the application of the best system of emission reduction” (BSER) that has been “adequately demonstrated.”
Chief Justice John Roberts authored the majority opinion, joined by Justices Thomas, Alito, Gorsuch, Kavanaugh and Barrett. | U.S. Supreme Court
The majority opinion, authored by Chief Justice John Roberts and joined by Justices Clarence Thomas, Samuel Alito, Neil Gorsuch, Brett Kavanaugh and Amy Coney Barrett, agreed with opponents who contended EPA’s authority to regulate power plants is limited to steps individual plants can make “inside the fence line.”
“At bottom, the Clean Power Plan essentially adopted a cap-and-trade scheme, or set of state cap-and-trade schemes, for carbon,” the court said. It reversed the D.C. Circuit Court of Appeals’ 2-1 ruling in 2021 that vacated the Affordable Clean Energy (ACE) rule, with which the Trump administration had proposed to replace the CPP. (See DC Circuit Rejects Trump ACE Rule.)
Roberts said the legality of the CPP was one of the “extraordinary cases” that require the court to weigh the “history and the breadth of the authority” claimed by an agency and the “economic and political significance” of its actions.
The court said the “major questions doctrine” was necessary to address “a particular and recurring problem: agencies asserting highly consequential power beyond what Congress could reasonably be understood to have granted.”
It cited previous rulings denying the Food and Drug Administration from claiming authority over tobacco products (FDA v. Brown & Williamson Tobacco, 2000); rejecting the Centers for Disease Control and Prevention’s authority to institute a nationwide eviction moratorium to prevent the spread of COVID-19 (Alabama Association of Realtors v. Department of Health and Human Services,2021), and the Occupational Safety and Health Administration’s mandate requiring employees obtain a COVID vaccine or undergo weekly testing (National Federation of Independent Business v. OSHA, 2022).
Before the CPP, the court said, EPA had always set emissions limits under Section 111 “based on the application of measures that would reduce pollution by causing the regulated source to operate more cleanly.”
The Biden administration disputed that characterization, citing EPA’s 2005 Clean Air Mercury Rule, which it says relied on a cap-and-trade mechanism to reduce emissions. But Roberts said that rule set an emissions cap based on what was achievable by technologies that could be installed on power plants. “By contrast, and by design, there is no control a coal plant operator can deploy to attain the emissions limits established by the Clean Power Plan,” Roberts said.
EPA said it was operating within the law by limiting its regulations to those that will not be “exorbitantly costly” or “threaten the reliability of the grid.”
“But this argument does not so much limit the breadth of the government’s claimed authority as reveal it,” Roberts wrote. “On EPA’s view of Section 111(d), Congress implicitly tasked it, and it alone, with balancing the many vital considerations of national policy implicated in deciding how Americans will get their energy. EPA decides, for instance, how much of a switch from coal to natural gas is practically feasible by 2020, 2025 and 2030 before the grid collapses, and how high energy prices can go as a result before they become unreasonably ‘exorbitant.’ There is little reason to think Congress assigned such decisions to the agency.”
While Congress amended the National Ambient Air Quality Standards statute to explicitly authorize use of cap-and-trade as a compliance mechanism, it did not do so regarding carbon or Section 111, Roberts said.
“Generation shifting can be described as a ‘system’ … capable of reducing emissions,” Roberts acknowledged. “But of course almost anything could constitute such a ‘system’; shorn of all context, the word is an empty vessel. Such a vague statutory grant is not close to the sort of clear authorization required by our precedents.”
“When Congress seems slow to solve problems, it may be only natural that those in the executive branch might seek to take matters into their own hands,” Gorsuch wrote in a concurrence with Alito. “But the Constitution does not authorize agencies to use pen-and-phone regulations as substitutes for laws passed by the people’s representatives.”
Dissent
Justice Elena Kagan wrote a dissenting opinion, joined by Justices Breyer and Sotomayor. | U.S. Supreme Court
The majority’s ruling denies EPA “the power Congress gave it to respond to ‘the most pressing environmental challenge of our time,’” Justice Elena Kagan responded in a dissent, quoting from the court’s 2007 ruling that carbon dioxide and greenhouse gases are air pollutants under the Clean Air Act and can be regulated by EPA (Massachusetts v. EPA).
“The majority’s decision rests on one claim alone: that generation shifting is just too new and too big a deal for Congress to have authorized it in Section 111’s general terms. But that is wrong. A key reason Congress makes broad delegations like Section 111 is so an agency can respond, appropriately and commensurately, to new and big problems,” said Kagan, who was joined by Justices Stephen Breyer and Sonia Sotomayor in the dissent.
“Section 111 does not impose any constraints — technological or otherwise — on EPA’s authority to regulate stationary sources (except for those stated, like cost). In somehow (and to some extent) saying otherwise, the majority flouts the statutory text,” she wrote.
“The current court is textualist only when being so suits it. When that method would frustrate broader goals, special canons like the ‘major questions doctrine’ magically appear as get out-of-text-free cards,” Kagan continued. “Today, one of those broader goals makes itself clear: prevent agencies from doing important work, even though that is what Congress directed. That anti-administrative-state stance shows up in the majority opinion, and it suffuses the concurrence.”
Kagan said even facility-specific controls dictate “the national energy mix to one or another degree.”
“That result follows because regulations affect costs, and the electrical grid works by taking up energy from low-cost providers before high-cost ones. Consider an example: Suppose EPA requires coal-fired plants to use carbon-capture technology. That action increases those plants’ costs, and automatically (by virtue of the way the grid operates) reduces their share of the electricity market. … Everything EPA does is ‘generation shifting.’ The majority’s idea that EPA has no warrant to direct such a shift just indicates that courts sometimes do not really get regulation.”
Kagan also challenged the majority’s fear of the cost of the Obama plan, saying the CPP, “we now know, would have had little or no impact.”
During arguments before the court in February, the Biden administration said the electric industry achieved the CPP’s emission limits a decade ahead of schedule — without the regulation in place. Opponents countered that although the standards were largely met nationwide, 20 states had not met them.
MISO’s $10.3 billion long-range transmission plan (LRTP) inched closer to approval Thursday as some board members advanced the project portfolio to the full board for its consideration later this month.
The Board of Directors’ System Planning Committee voted unanimously during a special conference call to recommend the full board take up the package’s approval in late July.
The first of four LRTP portfolios contains 18 345-kV projects in MISO Midwest. The portfolio is considered an addendum to the RTO’s 2021 Transmission Expansion Plan (MTEP).
“The portfolio shift is well underway,” Aubrey Johnson, vice president of system planning and competitive transmission, said during the call. “The future energy mix requires a broad and holistic solution rather than the type of approach we typically use with our annual MTEPs.”
Over the next 20 years, MISO conservatively expects 58 GW of mostly coal and gas resource retirements and about 90 GW of new gas and renewable resources, lowering the footprint’s carbon emissions down 63% from 2005 levels.
Director Nancy Lange asked how long it will take for the projects to become “regulatory realities.” Johnson said it should take about six to 18 months for the lines to gain state regulatory approval.
Johnson said his team will begin to prepare requests for proposals where state rights-of-first-refusal (ROFR) don’t prohibit competitive bidding. In states with ROFR laws, incumbent transmission developers will need to seek construction approval from their respective regulatory bodies.
MISO estimates that just $1 billion of the portfolio will ultimately be open to competition. The grid operator said nearly $4 billion worth of the projects are considered upgrades to existing facilities, while another $5.5 billion worth of projects are in states with ROFR legislation. Michigan, Minnesota, Iowa and the Dakotas all have ROFR laws; Wisconsin lawmakers have considered one but haven’t passed it.
Johnson said the RTO will likely manage multiple requests for proposals on the LRTP projects that can be competitively bid. “This will be the largest solicitation we’ve ever done,” he said at an earlier System Planning Committee meeting.
At the same meeting, Senior Vice President of Planning and Operations Jennifer Curran said the projects are based on a two-year-old “haircut” of MISO members’ resource planning. She said the projects are the product of a conservative future view and are crucial for reliability.
MISO’s sectors voted earlier in June to recommend the LRTP portfolio to the board. None of the 11 sectors opposed the transmission buildout; two abstained and the power marketers and end-use customers did not participate in the vote. (See MISO Makes Business Case on Long-range Tx Plan.)
MISO is also preparing for the LRTP’s second phase. The next round of projects will again be in the Midwest, much to some stakeholders’ frustration. It’s not until the third phase that the RTO will turn its attention to MISO South’s needs.
The grid operator will update its three, 20-year planning futures for its second collection of long-range projects. Johnson said a lot has changed since MISO last updated its futures in 2020.
Johnson said should the board approve the first LRTP portfolio, staff will provide “regulatory support” for state regulators on the first set of projects while beginning the hunt for the second portfolio’s projects.
“In many ways, we’re just getting started,” Johnson said.
Curran said MISO planners are expecting to defend the projects in front of state commissions. “We feel comfortable and confident that we’ve put together a strong case,” Curran said.
To shorten construction timelines and ensure simpler regulatory processes, the first LRTP cycle made use of existing rights of way. However, during a June 3 Entergy Regional State Committee Working Group meeting, MISO Senior Director of Transmission Planning Laura Rauch said the RTO isn’t sure it will take a similar approach in the South because there are benefits to “geographic diversity” of transmission lines in hurricane-prone areas.
Andy Kowalczyk, with the 350 New Orleans activist group, said MISO might consider building lines that could serve as alternative pathways to restore power in a post-hurricane blackout.
“How we get load back on is going to be critical,” Rauch agreed.
Rauch said strategically placed transmission can lessen the amount of generation states must build. “Transmission lets you optimize the generation you’re building,” he said.
Texas Public Utility Commission economist Werner Roth said MISO might want to emphasize reliability over economic benefits to better make its cases in front of state commissions.
Rauch said MISO agrees and said playing up economic benefits works because dollars are motivating.
Simon Mahan, executive director of the Southern Renewable Energy Association, said though MISO is likely understating economic benefits, stressing the reliability component will likely be the piece that “gets everyone on board” in MISO South.
None of the major utilities in the Southeastern U.S. are on track to decarbonize by midcentury or even by 2070, according to the Southern Alliance for Clean Energy’s (SACE) fourth annual decarbonization tracking report.
The alliance said that based on the current rate of change, Duke Energy won’t reach net-zero emissions until the next century. It said the Tennessee Valley Authority won’t achieve the emissions target until 2088, with Southern Company, Dominion SC and Next Era Energy decarbonizing in the early 2070s, the report said.
Although all five major utilities have announced net-zero emissions goals, only Duke and Next Era have expressed them in their integrated resource plans.
SACE emissions forecast of Southeastern utilities | SACE
SACE said Southeastern utilities will decarbonize more slowly from 2020 to 2030 than they did from 2010 to 2020.
“This is because utilities are seeing fewer and fewer emissions reductions from replacing coal generation with fossil gas,” SACE said in the report. “Fossil gas has been the dominant fuel in the region for several years, so utilities looking to decarbonize at the pace seen in the 2010s must continue to retire remaining coal plants at a steady pace and replace fossil gas and remaining coal with clean, zero-carbon energy sources like wind, solar, storage and energy efficiency.”
The organization said that current utility resource plans in the region indicate total CO2 emissions will decrease only 15% from current levels by 2030. SACE said utilities would need to cut emissions by 67% by 2030 to help limit climate warming to 1.5°C. That would cut about 105 million tons of carbon emissions annually by 2030, it said.
SACE also warned that “some utilities may see increased emissions in the next few years as high fossil gas prices mean utilities may decide to burn more coal.”
“If utilities had acted sooner, wind, solar and storage projects would have already been underway, avoiding some of this impact,” the alliance said.
SACE said wind and solar generation and energy efficiency measures accounted for 6% of the Southeast’s resource mix in 2020. Solar generation will account for all renewable energy’s gain when it comprises 13% of the mix by 2030.
The report found that the region’s total annual CO2 emissions have dropped about 20% from their peak in 2005, driven mostly by a 35 to 40% reduction in carbon emissions from the electricity industry.
The group said it foresees a troubling increased reliance on natural gas generation in the Southeast. It also said based on Duke Energy and TVA’s announced plans, the last coal units in the region would retire in the 2030-2035 timeframe.
SACE said the Southeast is positioned “first and worst” for climate impacts.
“The Southeast is home to many frontline communities that are already being negatively affected by fossil fuels and the climate crisis. Stronger and more frequent extreme weather events, coastal flooding, poor air quality and unpredictable energy prices are likely to continue to harm our communities,” the organization wrote.
SACE said the region’s decarbonization could pick up if more people become interested in utilities’ integrated resource planning.
A new report from the Brattle Group, commissioned by the Massachusetts Attorney General’s Office, has weighed in with recommendations for capacity accreditation as ISO-NE and NEPOOL are starting down the path of revamping how they value the contributions of energy resources.
ISO-NE first presented an outline in early June for how it plans to tackle capacity accreditation, starting what will be a yearlong stakeholder process on a significant change to the capacity market. (See ISO-NE Starts its Capacity Accreditation Journey.)
There will be opinions galore on the process, but the new report from the AG’s office is an early and potentially influential one.
The report looks at a number of methodologies for capacity accreditation to replace the region’s current Installed Capacity (ICAP) system, and lands on recommending what Brattle calls a “Hybrid Marginal Reliability Value based on Modeling and Empiricism.”
That option would rely on both historical measurements of resources’ performance and advanced reliability modeling, the report says, and tailor the specifics to New England’s needs and the characteristics of different resources. For example, for resources like wind and solar without batteries, the hybrid system could simulate their performance for an initial estimate, and then use historical measurements to get more specific about how the resources differ from the average of their class.
Accrediting other resources could rely primarily on historical data but also use model-based adjustments to account for outside factors like limitations on fuel. For each type of resource, the report acknowledges, “determining the best hybrid approaches to accreditation will require extensive development and calibration.”
Brattle makes a number of recommendations for while ISO-NE is developing its new approach. For example, the report calls for immediately upgrading accreditation for thermal resources, and not waiting for the full process to be complete.
“We suspect that thermal resources lacking firm fuel backup are the resources whose capacity ratings are most substantially overstated by current ICAP-based accounting methods in New England and therefore pose the most immediate reliability concern,” it says. Delaying application of a marginal value concept to these resources, while rushing it for others, “risks exacerbating present reliability concerns by amplifying economic incentives for resources with the most overstated capacity ratings.”
The report also recommends that ISO-NE improve its reliability modeling and implement seasonal accounting of reliability needs.
