A bill that would require all new electric vehicles to have bidirectional charging capabilities for vehicle-to-grid (V2G) or vehicle-to-home uses by 2027 cleared the California State Senate Energy, Utilities and Communications Committee on Tuesday despite opposition from large utilities and automakers.
Senate Bill 233 “will ensure that new EVs are equipped with bidirectional charging so that EV batteries have the ability to power homes or other facilities when electricity demand is at its peak and prices are high,” the bill’s author, Sen. Nancy Skinner, wrote in a statement on the need for the bill. “With bidirectional charging, EVs also have the potential to help power the grid.”
California has a requirement that 100% of new passenger vehicles sold in-state must be zero-emission by 2035, with interim goals of 35% by 2026 and 68% by 2030.
The California Electric Transportation Coalition (CalETC) — a group whose members include Pacific Gas and Electric, Southern California Edison and the Los Angeles Department of Water and Power — said Skinner’s bill could hinder EV adoption and undermine the state’s efforts.
“The ramifications of setting a mandatory deadline requiring EVs and chargers to be bidirectional-capable will be detrimental to the EV market and risks increasing costs at a time when zero-emission technology needs to be more accessible to consumers, especially equity communities,” the group wrote in a letter opposing the measure.
“The V2G and bidirectional charging technology market is still nascent, and it is unclear which use cases justify the costs,” it said. “Further, the lion’s share of benefits to grid stability and resiliency are expected to be realized with managed charging through V1G [unidirectional smart charging] technology in the near to medium term and at much lower cost.”
At Tuesday’s hearing, Skinner noted that all Nissan Leafs have been bidirectional since 2013 and remain among the most affordable on the market. All Tesla models will be bidirectional starting with the next model year, she said.
“We’re already moving in this direction, but we need all of our vehicle manufacturers to move their EVs to bidirectional, so that we have that capability,” she said. Doing so could save ratepayers money and promote grid reliability during times of high demand, she said.
“With the expectation that 8 million EVs will be on the road by 2030, if less than 10% of those EVs were utilized in this way, it would have more gigawatt capacity than Diablo Canyon has today,” she said.
Diablo Canyon, the state’s last operating nuclear power plant and its single largest power source, has a 2.2-GW generating capacity.
Supporters of the bill include the Sierra Club, the Union of Concerned Scientists and community choice aggregator Marin Clean Energy.
In their analysis of the bill, committee staff suggested lawmakers might want to amend the bill to remove its mandates and instead direct the California Energy Commission and Air Resources Board to study the availability of bidirectional EVs and chargers, as well as the costs and benefits of bidirectional EV charging and discharging to the grid.
The Alliance for Automotive Innovation — a group whose members include Ford, General Motors and Toyota — said it would oppose the bill unless the mandates were removed and urged the committee to follow its staff’s suggestions.
Skinner accepted an amendment to remove a mandate that EV charging equipment be bidirectional by 2027 but did not remove the vehicle mandate.
Curt Augustine, head of state affairs for the auto alliance, said he was “perplexed” by the move.
“She is exempting all the utilities, the service providers [and] the charging units but requiring a mandate on the automakers,” he said.
Some committee members expressed concerns with the measure, including its potential effects on EV affordability for low-income residents, but they passed it 12-1. It goes next to the Senate Transportation Committee.
FERC on Tuesday approved a PJM proposal to overhaul how generators can represent variable operating and maintenance (VOM) costs in their energy market offers (ER23-1138).
The proposal sought to divide generators’ maintenance adders into “major” and “minor” buckets and allow the owners to opt for newly created default values for minor maintenance. The proposal also would create default values for operating expenses, which — like minor maintenance — have a tendency to be fairly uniform year-over-year, PJM said. (See “MRC Approves VOM Package,” PJM MRC Briefs: Nov. 16, 2022.)
The April 18 order said the proposal streamlines the process for approving maintenance and operating costs, while retaining market power protections. The order granted PJM’s requested June 1 effective date.
“PJM’s proposal offers market sellers flexibility while maintaining essential safeguards to mitigate opportunities for market sellers to exercise market power,” the commission said.
Under the status quo rules, generators are required to submit documentation of any maintenance and operating expenses they’re seeking to include in their cost-based offers, which the filing said causes “significant administrative burdens for both market sellers and PJM.”
The maintenance history used to calculate corresponding adders includes costs going back 10 to 20 years, which results in time spent reviewing and approving those costs each year, PJM said. The proposal allows expenses for major maintenance to be approved with an “expiration date,” after which costs must be resubmitted.
Major maintenance expenses would also be required to be resubmitted if they are no longer accurate due to expenses rolling off the 10- or 20-year historical period.
Generators would still have the option to submit unit specific costs for minor maintenance and operating expenses. However, PJM argued that the process of submitting, reviewing and approving expenses typically takes several months on behalf of sellers, RTO staff and the Independent Market Monitor.
Default adders would not be created for nuclear and hydroelectric resources, which PJM said lack the historical data being used to create the adders for other resource types, nor for wind and solar, which the filing said typically don’t submit maintenance adders. PJM may seek to create those adders in the future.
The proposal defines major maintenance as “overhauls, repairs, or refurbishments that require disassembly to complete of boiler, reactor, heat recovery steam generator, steam turbine, gas turbine, hydro turbine, generator, or engine.” Minor maintenance is described as “typically performed when there is a component failure or prior to a component failure due to limited remaining component life” and that can be completed while the generator is operating or during short shutdowns.
Monitor Protests Inclusion of Avoidable Costs
The Monitor argued that PJM’s proposal incorrectly allows maintenance costs that are avoidable costs and should be included in capacity offers to be instead submitted as short-run marginal costs in the energy market.
The issue arises from a vague definition of maintenance costs, the protest states, allowing all costs “directly related to electricity production” to be included in energy offers.
To support its position that maintenance costs should be included in capacity offers, the Monitor pointed to a filing to allow the Indian River 4 coal-fired unit to provide service after its deactivation request, in which it seeks to receive a lump-sum payment for its maintenance-related investments rather than recovering those expenses through the energy market. The protest also states that 53% of marginal units in the energy market included maintenance costs in their 2022 energy market offers.
PJM responded that its proposal doesn’t seek to change the existing requirement that maintenance adders can only be recovered in the energy market and through the avoidable cost rate (ACR) in the energy market. It also argues that the Monitor’s objections have been raised in past dockets and constitutes a collateral attack on the commission’s 2019 order approving PJM’s maintenance adders revisions (EL19-8).
In this week’s order, the commission noted that it had addressed the concerns raised by the Monitor in 2019.
“The wear and tear of operating a resource is typically based on the number of starts or run hours, and the maintenance intervals can be influenced by resource output levels. As such, it is reasonable to assume that some maintenance costs are incurred as the result of operating the resource, even if such costs are not incurred immediately at the time of production,” the commission said in its 2019 order, cited in the recent finding.
FERC took the final step on Thursday in fulfilling its obligation to encourage voluntary investments in cybersecurity by electric utilities, as directed by Congress two years ago (RM22-19).
Congress ordered FERC to develop its cyber incentive plan in the Infrastructure Investment and Jobs Act of 2021, which mandated that the commission establish financial incentives for public utilities to invest in “advanced cybersecurity technology” and participate in cybersecurity threat information-sharing programs.
FERC Chair Willie Phillips | FERC
“In today’s highly interconnected world, our nation’s security and economic wellbeing depend on reliable and cyber-resilient energy infrastructure,” FERC Chair Willie Phillips said in a statement. “We must continue to build upon the mandatory framework of our cybersecurity reliability standards with efforts such as this to encourage utilities to proactively make additional cybersecurity investments in their systems.”
The final rule approved Thursday is largely similar to the Notice of Proposed Rulemaking that FERC issued last September. (See FERC Reluctantly Proposes Cybersecurity Incentives.) It sets three ways utilities may qualify for the incentives:
any investment included in a prequalified list of cybersecurity expenditures with a rebuttable presumption of eligibility;
investments needed to establish compliance with NERC’s mandatory Critical Infrastructure Protection (CIP) standards that are not yet enforceable; and
investments not included in either of these categories but “tailored to their specific situations” and approved by FERC on a case-by-case basis.
The first qualification was already given in last year’s NOPR; the latter two were added for the final rule. Eligible investments must be for technology that “materially improves” a utility’s cybersecurity posture and is not already mandated by law or the CIP standards. Expenses for participating in threat information-sharing programs would also qualify for reimbursement.
Also included from the NOPR is the proposal to allow deferred cost recovery for eligible investments, through which utilities may add the unamortized portion of the expenses to their rate base.
An alternative means of compensation that would have provided a return on equity adder of 200 basis points was not adopted in the final rule. Commissioner Mark Christie criticized the idea as “FERC candy” when it was brought up in September, saying it was “pretty sour for consumers” who would end up paying utilities significantly more for doing what they “ought to do anyway.”
Incentives will remain in effect for up to five years from the date the expenses are incurred, with some exceptions, as long as the investments remain voluntary.
The only dissenting vote on the measure came from Commissioner James Danly, who said at Thursday’s meeting that despite the “unambiguous declarations of Congress and [their] clear purpose [of] directing us to incentivize certain types of investments,” FERC had chosen an “insufficient” path for fulfilling its mandate.
“We can quibble all we like about whether or not [the law] was the right way to do it; it doesn’t matter,” Danly said. “We’ve been given our marching orders by Congress, and it has been a matter of continuous interest to any number of policymakers that we take more aggressive stances on cybersecurity. This rule fails to encompass a sufficient quantity of the entire electric system, and it demands certain levels of materiality that I think are simply not appropriate given the statutory language.”
Danly tempered his criticism with praise for Phillips’ “enthusiastic and unflagging … support for ensuring that the NERC reliability standards are up to scratch.”
The final rule will take effect 60 days following its publication in the Federal Register. FERC had not published its order approving the rule as of press time.
More than 1.5 million light-duty electric vehicles have now been sold in California, beating by two years the target set by a governor’s executive order in 2012.
The state reached the 1.5-million EV milestone during the first quarter of this year, according to data released Thursday by the California Energy Commission. And 21% of new cars sold in California in the first quarter were electric. The EV data include battery electric vehicles, plug-in hybrids and hydrogen fuel cell EVs.
In March 2012, Gov. Jerry Brown issued executive order B-16-2012, calling for 1.5 million zero-emission vehicles on California roads by 2025.
At the time, many viewed the target as a “moonshot,” or aspirational goal, state officials said during a media briefing on Thursday. At the end of 2011, only 6,743 EVs had been sold in the state.
“When Gov. Brown set this goal, people across the state and around the nation said it couldn’t be done,” said Lauren Sanchez, senior climate adviser to Gov. Gavin Newsom. “But here in California, we make the future happen. We don’t just set goals, we achieve them.”
California Air Resources Board Chair Liane Randolph credited the state’s zero-emission vehicle (ZEV) regulations for spurring ZEV technology and manufacturing.
“The industry has responded incredibly rapidly to the confluence of market pressures, consumer demands and regulatory requirements,” Randolph said during the briefing.
In 2012, CARB adopted its initial Advanced Clean Cars regulation, which requires an increasing percentage of zero-emission cars to be sold each year. In August, the agency adopted Advanced Clean Cars II, which requires all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
ZEV adoption in California also has been boosted by nearly $2 billion in purchase incentives, officials said.
“California is setting the bar for climate action,” Newsom said in a statement. “And we’re achieving our goals years ahead of schedule thanks to unprecedented investments secured in partnership with the Legislature.”
The 1.52 million light-duty EVs sold in California through the end of the first quarter of 2023 represent 42% of the 3.61 million EVs sold in the U.S.
“The transition to ZEVs is here, and it’s happening quickly,” California Energy Commission member Patty Monahan said during Thursday’s media briefing.
The CEC is playing a lead role in ensuring enough charging infrastructure and hydrogen-fueling stations are built to support the growing number of EVs. A 2021 analysis found that the state will need 1.2 million public and shared private charging ports to support 8 million plug-in electric passenger vehicles in 2030, Monahan said. The CEC expects to release this year an updated analysis of EV charger demand.
According to figures released Thursday, California had 87,707 EV chargers and 63 hydrogen-fueling stations at the end of the first quarter.
Monahan said efforts are also underway to improve the reliability of public chargers. Drivers often find that chargers don’t work at the public stations, or there’s a glitch in using their credit cards, she said. CEC is developing reporting requirements for the reliability of publicly funded chargers and will publish a report on the reliability of the state’s EV charging network.
In addition, Monahan said, EVs must be “good citizens of the grid.” An analysis found that EVs will account for less than 5% of peak load in 2030. But that demand must be managed wisely, she added.
“With the right incentives, vehicles could shift charging from peak times to the middle of the day,” Monahan said. “You could literally run your vehicle on sunshine, and we wouldn’t have to curtail renewable energy.”
NYISO on Tuesday announced that veteran energy regulator Sally Talberg had joined its Board of Directors as its ninth member.
Talberg has 25 years of experience in energy and environmental regulation and has served in multiple top-level capacities.
She was appointed by Michigan Gov. Rick Snyder (R) to the Public Service Commission in 2013, serving as its chair from 2016 to 2020. During that time, she was a member of both the National Association of Regulatory Utility Commissioners and the U.S. Department of Energy’s State Energy Advisory Board. In 2016, Talberg served as president of the Organization of MISO States.
Sally Talberg | Michigan Public Service Commission
Talberg left the Michigan PSC near the end of 2020 to join ERCOT’s Board of Directors, first as an independent director for the first month of 2021 and then as its chair beginning in February — just before Winter Storm Uri hit and nearly caused the collapse of the Texas Interconnection. She, along with three other independent directors of the board, resigned later that month after fierce criticism from state residents about ERCOT’s out-of-state leadership in the aftermath of the storm. (See ERCOT Chair, 4 Directors to Resign.)
Talberg did, however, begin her career in Texas, after graduating from Michigan State University. She worked at the Lower Colorado River Authority while pursuing her master’s in public affairs from the Lyndon B. Johnson School of Public Affairs at the University of Texas at Austin. She went on to work at the Texas Public Utility Commission as an electric policy analyst.
“As a former state commissioner and former adviser to commissioners at the Texas and Michigan commissions, she has a unique appreciation for the importance of market design, infrastructure planning, pragmatic regulation and stakeholder engagement,” NYISO said.
Currently, she runs her own consultancy, Talberg Policy Solutions, and serves as a senior policy fellow at Public Sector Consultants.
The NYISO board consists of 10 members; Talberg’s appointment leaves just one vacancy.
“It is a privilege to welcome Sally to the NYISO’s Board of Directors. Her extensive experience will be invaluable as the board guides the NYISO during this historic period of industry change,” Chair Daniel Hill said in a statement. “We look forward to Sally’s contributions as we work to meet the state’s climate mandates, ensure grid reliability and competitive wholesale markets during the grid in transition.”
AES (NYSE:AES) and FirstEnergy (NYSE:FE) announced an agreement Tuesday to terminate their power purchase agreement for the 205-MW Warrior Run coal-fired power plant almost six years early, with plans to shutter the western Maryland plant by 2025.
FirstEnergy subsidiary Potomac Edison has been buying the output of the plant for decades under the Public Utility Regulatory Policies Act (PURPA) and bidding its output into PJM. The utility’s ratepayers will be on the hook for another $357 million if the deal is approved by the Public Service Commission, but that would save them $80 million over the next seven years while helping Maryland reach its decarbonization goals.
The PPA, which obligated Potomac Edison to purchase up to 180 MW/hour through Feb. 10, 2030, would terminate at the end of May 2024 under the utility’s petition (ML# 302441).
“This agreement is another milestone in our journey toward decarbonization,” AES CEO Andrés Gluski said in a statement. “Following the contract termination, we see interesting opportunities to repurpose the Warrior Run site for low carbon solutions that continue to serve local communities.” No details were provided on those plans.
The plant would keep operating through at least May 2024 — the end of PJM delivery year 2023/24 — which is in line with AES’ corporate goal of exiting the coal generation business by 2025, FirstEnergy told the PSC.
Potomac Edison has been buying the plant’s output under PURPA since the state restructured in 1999 and has been selling its output into PJM’s market since 2008, which is the most cost-effective way of generating income for the plant. Through 2022, the utility has paid AES $1.3 billion in excess of its wholesale power revenues, FirstEnergy told the PSC.
That money has been recovered from customers under a surcharge that varies significantly depending on wholesale prices, but has made up as much as 15% of the average customer’s bill when wholesale prices are low, the utility told the PSC.
Even with recent wholesale market volatility, the two firms expect the early termination fees to be cheaper than what Potomac Edison would have to pay under the remainder of the contract.
The wholesale volatility has not all been to the benefit of the plant. During the winter storm in December 2022, it underperformed on one day and owes $2 million in capacity performance payments to PJM.
“While the events of December 23 and 24, 2022, are uncommon and excessive compared to normal conditions, removing these operational risks along with the market volatility risk can provide significant benefit and protection to PE’s customers,” the PSC filing said.
The firms asked the PSC to decide on their request to retire the plant early by June 30. If it is approved later, the consumer benefits will be lower as they will have to renegotiate, the companies said.
AES said it would work with the plant’s employees to manage a responsible transition and will maintain full operational control over the site after it is decommissioned.
LANSING, Mich. — Democrats introduced a package of seven energy and climate bills Wednesday that would end coal-fired electric generation in the state by 2030 and mandate 100% renewable electric production by 2035.
SB 276, introduced by Sen. Rosemary Bayer (D), calls for the state’s coal-fired power plants to be phased out by 2030, putting it at odds with DTE Energy (NYSE:DTE), which operates a 3,280-MW coal plant near Monroe.
According to the Sierra Club’s Beyond Coal campaign, the only other plant that might be affected by the bill is the 70-MW TES Filer City Station, which is owned in part by CMS Energy (NYSE:CMS).
Michigan greenhouse gas emissions by source | MI Healthy Climate Plan
“TES has a planned retirement date of 2025, according to [the Energy Information Administration], but Sierra Club has not counted it because their contract with Consumers Energy ends in 2025, and they haven’t made any solid plans for the future, which means theoretically they could sign an agreement with another power purchaser, retire or convert to gas,” the Sierra Club said.
CMS has announced it would close all three units at the J.H. Campbell coal plant in West Olive in 2025 in addition to two units at the D.E. Karn coal plant in 2023. (See Mich. PSC OKs CMS Plan to End Coal Use by 2025.)
Senate Democrats announced their legislative plans last week as some 600 people met in Detroit at the state’s first Healthy Climate Conference.
The other bills are:
SB 271, introduced by Sen. Erika Geiss, would mandate 100% renewable electric production by 2035.
SB 272, introduced by Sen. Sue Shink, would give the Public Service Commission authority to consider climate, public health, social equity and price affordability issues in integrated resource plans by regulated utilities.
SB 273, introduced by Sen. Sam Singh, would require municipally owned and cooperative utilities to continue participating in energy-efficiency programs (eliminating a 2021 sunset provision).
SB 274, introduced by Shink, would require the development of a plan to reduce greenhouse gas emissions from buildings, including a zero-emission standard for new construction after 2026.
SB 275, introduced by Singh, is intended to reduce the carbon intensity of transportation fuels to 25% below a 2019 baseline by the end of 2035. The bill, which would also establish a market for trading carbon intensity credits, would exempt aviation fuels from the clean fuels standard, although sustainable aviation fuel would be eligible to generate credits.
SB 277, introduced by Sen. Kristin McDonald Rivet, would allow farms enrolled in Michigan’s farmland preservation program to lease out land for solar energy projects.
None of the bills in the package are tie-barred, meaning if some bills are blocked from passage, the others could still take effect.
Lisa Wozniak, executive director of the Michigan League of Conservation Voters, praised the proposals, saying recent polling showed most Michigan residents want the state to take greater action to fight climate warming. “This legislation will set Michigan on a path toward cleaner air, good-paying jobs, lower costs and a healthy, livable future,” she said.
Singh said the bills will help the state meet the goals of the MI Healthy Climate Plan. Adopted by the administration of Gov. Gretchen Whitmer (D) in 2022, the plan calls for the state to build the infrastructure for 2 million electric vehicles by 2030 and achieve carbon-neutral status by 2050.
If approved, the bill package would be the most significant action Michigan’s legislature has taken on climate issues since 2016, when the Republican-controlled state government enacted a bill requiring utilities to produce at least 15% of electricity by renewables by the end of 2021.
Now, following the 2022 election, the governor’s office and the legislature is under Democratic control, albeit with Democrats holding narrow majorities in both the House of Representatives and Senate. Under Michigan’s constitution, bills passed this year with less than two-thirds approval would not take effect until March 31, 2024.
While Democrats’ legislative package matches proposals urged by environmental groups at the start of the climate change conference, Whitmer did not call for any specific plan of action in her keynote address to the conference. Instead she praised the progress the state has made thus far, noting it has increased its renewable capacity from 17 MW in 2009, to 3,554 MW in 2022.
Whitmer last week also promoted a plan in her proposed 2023/24 budget to exempt EVs from Michigan’s 6% sales tax for two years. That proposal could save motorists up to $2,400 on a $40,000 EV, while costing state coffers some $48 million.
DTE Opens 225-MW Wind Farm
Adding to the state’s renewable fleet, DTE on Tuesday announced that it has officially opened the state’s largest wind farm, a 225-MW project spanning sections of Saginaw and Midland counties. (There is actually one larger wind project in the state, also owned by DTE in Isabelle County, generating 383 MW, but it is split into two separate farms.)
Avangrid (NYSE:AGR) won another round Thursday in the long-running court battle over the $1 billion, 1,200-MW transmission line it is attempting to build in Maine.
A jury in Portland decided the developer had a right to resume construction of the New England Clean Energy Connect, which would bring hydropower from Quebec to Massachusetts.
Maine residents rejected NECEC in a November 2021 referendum, and groups such as the Natural Resources Council of Maine have mounted one legal challenge after another, stalling a project first floated in 2017.
The trial ending Thursday was held to resolve a question unanswered in the November ruling: Whether the developer had vested rights to complete construction of the line.
The jury unanimously decided that it does.
But that is not necessarily the final chapter in the saga, as NECEC opponents could appeal Thursday’s verdict to the state Supreme Judicial Court. The Portland Press Herald noted that NECEC still faces appeals in state and federal court of permits issued by the state Department of Environmental Protection and U.S. Army Corps of Engineers.
Nonetheless, Avangrid welcomed the verdict as a victory.
“The jury’s unanimous verdict affirms the prior rulings of the Maine Supreme Judicial Court that the New England Clean Energy Connect project may lawfully proceed,” Senior Vice President Scott Mahoney said in a news release. “Even after repeated delays and the costs caused by the change in law, the NECEC project remains the best way to bring low-cost renewable energy to Maine and New England while removing millions of metric tons of carbon from our atmosphere each year.”
“We are pleased that this project can continue to move forward,” Vice President Anne George said in a news release. “The New England states’ ambitious climate goals will require building significant amounts of new infrastructure in a region where building infrastructure has been difficult. ISO New England looks forward to continuing our work with the New England states and other stakeholders, to making a clean and reliable future grid a reality.”
NECEC would be part of the system operated by Central Maine Power, an Avangrid subsidiary. The roughly 145-mile line is expected to import approximately 9.5 TWh/year of electricity generated by Hydro-Quebec. Avangrid said it would save Massachusetts ratepayers $190 million a year while reducing emissions by the equivalent of 600,000 cars. Completion was initially projected in 2023 when work began in early 2021.
Fierce opposition erupted on multiple fronts in Maine, where some residents were concerned about the environmental impact of a project that would not directly benefit their state.
Other opposition was more subtle.
NextEra Energy (NYSE:NEE), whose 1.24-GW nuclear power station in Seabrook, New Hampshire, might suffer in competition with an influx of low-cost electricity, supported efforts to block the line.
NextEra and Avangrid also squabbled over a circuit breaker at Seabrook that would be necessary once NECEC came online. The matter went to FERC — which ruled that NextEra could not refuse to install it — but the two had worked out an agreement by that point. (See FERC Resolves NextEra-Avangrid Dispute over Seabrook Circuit Breaker.)
WASHINGTON — Democrats in Congress want legislation to streamline and speed up permitting for clean energy projects and transmission, while Republicans want it for mining and drilling on federal lands, and for pipelines for hydrogen and carbon capture projects as well as for oil and natural gas, according to Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee.
And both sides know new laws will be vital for developing domestic supply chains for critical minerals, such as lithium, cobalt and nickel.
Somewhere between these “essential views,” Capito said Tuesday at a breakfast meeting at the U.S. Chamber of Commerce, is the possibility to “forge a compromise … to say to the Democrats on our committee and Republicans on our committee, we may be approaching this from a different angle on where our real needs are.
“Successful legislation is about not just getting but giving up the things that you really don’t want, and so to get there we’re going to have to have that mindset across the committee,” she said.
“Permitting reform,” as it is commonly referred to, has become a high priority for both parties in the 118th Congress and for the Chamber, which has launched its own lobbying campaign called “Permit America to Build.” Tuesday’s event was a kick-off for the campaign, timed to coincide with a fly-in lobbying effort by members of the American Clean Power Association.
The goal for a range of stakeholders is bipartisan legislation that will provide “meaningful” change and break through the congressional inertia that has long surrounded the issue, said Neil Bradley, chief policy officer at the Chamber.
“Unfortunately, this is one of those issues where failure doesn’t immediately lead to catastrophic consequences,” Bradley said. “When we push permitting reform, it’s easy to keep talking about it; it’s easy to keep insisting on one position — your side’s position — while the other side insists on theirs. … Maybe we’ll find a solution later; maybe we’ll get a better outcome after the next election.”
Leonardo Moreno, president of AES Clean Energy, said the lack of consistency in permitting processes is a key challenge for his company’s efforts to build new solar, wind and storage projects. “If you go to agencies in each of our regions in the U.S., the main agencies are the [Bureau of Land Management], the Army Corps of Engineers and Fish and Wildlife,” Moreno said. “They don’t apply [the National Environmental Protection Act] in the same way; each of them has their own way of applying the process.”
Staff turnover can also mean further delays, leading to requests for new studies on different issues, he said.
But if the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act has not exactly created a sense of urgency, they have at least prompted some serious momentum around the long-dormant issue. The two laws are pouring billions of federal funds into a range of clean energy and other infrastructure projects, and the byzantine federal permitting process is now seen not only as a roadblock for clean energy and other infrastructure but as a national security issue that is integral to building out domestic supply chains.
Exhibit A is the 732-mile TransWest Express transmission line, which filed its first application for a right-of-way on federal land back in 2007 and only recently received final approval from the Bureau of Land Management to start construction. Completion is targeted for 2027, when the high-voltage line will send power from Wyoming wind farms to Southern California. (See TransWest Express to Break Ground After BLM Approval.)
Both EPW and the Senate Natural Resources (ENR) Committee have scheduled hearings on permitting reform, with Sen. Joe Manchin (D-W. Va.) announcing that a Thursday hearing on the Department of Energy’s 2024 budget will take up the issue. Energy Secretary Jennifer Granholm is scheduled to appear.
EPW will hold a hearing specifically on permitting on April 26, as will ENR on May 11.
“These upcoming hearings are vital to understanding how we can achieve bipartisan consensus that makes it possible for America to build again and maintain our status as a global energy leader,” Manchin said in an email statement. “Americans cannot wait any longer, and neither can I.”
NEPA Not Sacrosanct
The question remains: Can a divided Congress pass substantive legislation on permitting, especially when the ruling parties in both houses have narrow majorities?
While Senate Majority Leader Chuck Schumer (D-N.Y.) pronounced the House Republicans’ energy bill H.R. 1 “dead on arrival,” both Capito and Manchin said its permitting provisions, which are almost exclusively focused on fossil fuels, could provide a starting point.
“Nothing should be dead on arrival,” Manchin said at the Chamber event, arguing that looking at the opposition’s proposed legislation allows for a process of improvement. “We’re not going to have a perfect piece of legislation, [but] we can have a piece of much better legislation,” he said.
Both Manchin and Capito introduced permitting bills after passage of the IRA. Capito’s Simplify Timelines and Assure Regulatory Transparency (START) Act (S. 4815), stalled out in the EPW Committee, while Manchin made repeated efforts to get his Building American Security Act into other must-pass legislation, such as the National Defense Authorization Act. (See Manchin Permitting Bill Falls Short in Senate.)
Capito laid out what she sees as the core components of any compromise legislation.
First, she said, the bill should be “technology- and fuel-neutral to benefit energy projects of all kinds,” as well as other infrastructure projects, including roads, water and broadband. Another key component would be “enforceable deadlines.” When federal agencies don’t meet deadlines, “what happens?” Capito said. “Basically nothing. … All it does is push more and more of the burden onto whoever the developer is, the builder is, the community is.”
A 60-day deadline for filing judicial challenges to an approved project is another must-have, Capito said. “We’re going to first ask for some substantive changes to the NEPA review, also to the Clean Water Act. … That may be too far of a stretch, but we’re going to try.”
But Rep. Scott Peters (D-Calif.), a former environmental lawyer, says NEPA is not sacrosanct. “That approach simply is not compatible with science [and] the time we have left to maintain a stable climate,” he said.
Peters has made permitting legislation his personal mission and is working across the aisle with Rep. Bruce Westerman (R-Ark.) to find bipartisan solutions. For example, Peters said, “we can reduce the level of review for climate projects on nonsensitive land. … There’s no reason a solar project on degraded land, miles away from people, should go through the same process as a community [solar] project in a local community.”
Judicial review processes should be tweaked “to protect vulnerable communities while preventing wealthy NIMBYs and bad actors from blocking central clean energy projects … and ensure the federal government has the authority to build a reliable, environmental grid,” Peters said.
“If 52 years after NEPA, we’re still complaining about the effect of pollution on underserved communities … it’s time to expand our conversation,” he said. “When there’s so much money out there to do clean energy, and whether you’re a climate activist or just a taxpayer, you don’t want to see that money wasted on process.”
Good Things Fast
The Chamber’s goal is to get a “durable, meaningful” permitting bill passed by the end of the summer, and it aims to keep up the pressure with its lobbying campaign, according to an organization spokesperson.
“In the coming weeks and months, we will hold additional events activating our vast state and local Chamber network,” the spokesperson said. “There will be many conversations both inside and outside the Beltway, and … we will work closely with members of the House and Senate on legislative language consistent with our principles.”
Similar to Capito’s core components, the Chamber is calling for permitting that provides predictability and transparency for businesses, better coordination between federal agencies and broad stakeholder input.
But Jason Grumet, CEO of the American Clean Power Association, believes a more basic shift in mindset is going to be needed. Focusing on national security, economic development and government efficiency have, to date, not gotten the job done on permitting because “there was a perception that this was trying to advance an energy system that was not consistent with environmental imperatives,” he said.
The inefficiency of permitting has been “weaponized” and used to slow down or prevent “high-target infrastructure,” Grumet said.
“There is absolutely no political coalition that can move forward legislation that is simply focused on fossil [fuels],” he said. “There is equally absolutely no possibility of moving legislation through a closely divided Congress that is only focused on clean energy. …
“There’s not a single piece of legislation that can pass this Congress that will be the end of the discussion,” Grumet said. “But it is the beginning of shifting our national consciousness to recognize that making good things happen fast is the future of the country.”
Capito would also like to see a bipartisan permitting bill passed before Congress adjourns for its August recess. While some House Republicans have suggested attaching H.R. 1 to any deal on raising the national debt limit, Capito said the priority should be getting the bill right.
“Get the policy right,” she said. “And then we’ll find the vehicle.”
FERC last week rejected SPP tariff revisions that would help transmission owners continue to self-fund network upgrades to interconnect generators (ER22-2968).
The commission found in a 3-1 decision on April 14 that SPP had not demonstrated that its proposed pro forma facilities service agreement and associated tariff revisions were just and reasonable and not unduly discriminatory or preferential (ER22-2968).
The grid operator sought approval of a proposal to allow TOs to self-fund the upgrades and recover their costs and a return on investment from an interconnection customer.
American Clean Power Association, Advanced Power Alliance, the Solar Energy Industries Association, the Natural Resources Defense Council and the Sustainable FERC Project all intervened against the revisions. They said the self-funding would heap costs on generation developers if they didn’t pay for the upgrades themselves.
FERC said SPP’s proposal ran counter to Order 2003, which established standard interconnection procedures to limit opportunities for transmission providers to favor their own generation and facilitate market entry for generation competitors by reducing interconnection costs and time.
The commission said the revisions could lead to “greater uncertainty” for interconnection customers that might not elect to a TO’s initial funding for upgrades, but then reverse course near the study process completion. It agreed with the clean energy advocates’ argument that such circumstances could lead to late-stage withdrawals and delays in administering the generator interconnection queue, further undermining Order 2003’s goals.
SPP and Xcel Energy subsidiary Southwestern Public Service contended that a non-binding indication provides an interconnection customer advance notice that a TO intends to self-fund prior to negotiation of generator interconnection. They also noted that FERC approved MISO’s request to require TOs to make binding self-funding decisions before GIA negotiations begin.
FERC disagreed, saying the non-binding self-funding election means a TO can make a choice when the study process begins and then do the opposite. The commissioners said they accepted MISO’s revisions to add deadlines by which TOs must make both non-binding and binding elections before the GIA negotiations. They said SPP’s proposal includes only the non-binding indication provision.
“Having more information earlier is beneficial not harmful,” the commission wrote. “By denying an earlier indication of the transmission owner’s potential election, interconnection customers will be denied access to information at an earlier stage under the tariff. That denial of information actually creates uncertainty; it does not protect against it.”
Commission Nixes PRM Waivers
The commission on Monday also rejected SPP tariff revisions that would allow load-responsible entities (LREs) to obtain two-year exemptions from deficiency payments assessed for not meeting the grid operator’s new resource adequacy requirement, finding the grid operator had not demonstrated the proposal was just and reasonable (ER23-636).
The commission found the RTO’s proposal would undermine the structure of deficiency payments, set out in a 2018 filing to establish the resource adequacy requirement. LREs unable to meet the requirement are subject to a deficiency payment equal to the payment amount multiplied by the cost of new entry and a multiplication factor of the footprint’s excess capacity relative to the planning reserve margin (PRM).
“The complete elimination of the deficiency payment, even under the criteria of the proposed exemption process, removes the incentive for LREs to procure the capacity needed to collectively ensure that the SPP footprint maintains resource adequacy,” the commission wrote.
FERC has said SPP’s proposed deficiency payment “provides a signal to LREs to plan ahead to satisfy the [resource adequacy requirement].”
The commission found that while the proposed exemption is limited to two hours each time the grid operator increases the PRM, LREs would be able to seek the exemption each time there is an increase. It said that, were SPP to make consecutive increases, deficient LREs with exemptions wouldn’t be required to meet their resource adequacy obligations for an extended time.
FERC also said the proposed tariff language is not clear as to how the proposed exemption process would work.
Evergy’s Denise Buffington, who warned last October that the proposal would fail at FERC, suggested SPP’s future tariff revisions should allow more time for compliance.
“It takes time to get steel in the ground, and if SPP continues to increase the performance or planning reserve margin on an annual basis, we’re never going to be able to meet it,” she said during a Resource and Energy Adequacy Leadership Team meeting Thursday. “When we think about setting out new requirements, we have to do them far enough in the future so that load-responsible entities can actually comply.”
