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November 4, 2024

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FERC Approves Most of CAISO’s Rule Changes for EDAM Participation

FERC has issued an order partly approving rule changes CAISO filed to its tariff that are meant to enable its participation in the Extended Day-Ahead Market (EDAM) once it goes live (ER24-379). 

The EDAM tariff is the largest and most complex suite of software enhancements since CAISO’s market redesign and technology upgrade almost 15 years ago, and it requires the ISO itself to change its internal rules to participate smoothly. 

On March 7, FERC accepted all of the proposed rules except for the proposal to calculate EDAM historical revenue recovery, which drew a protest from Southern California Edison.  

EDAM participation might affect the allocation of revenues that transmission owners get for using their transmission system, and the ISO proposed an “EDAM access charge” to recover any shortfalls relative to historical revenues. 

The charge is designed to recover three types of costs: foregone historical transmission revenue from sales of short-term firm and nonfirm transmission products under the transmission service provider’s tariff; any new lines that get approved to increase transfer capability between EDAM entities based on the proportional ratio of historical short-term sales to overall historic transmission revenues; and foregone revenues for the use of the grid when wheeling through transfer volumes in a balancing authority are greater than total import and export transfer volumes for it. 

SCE did not take issue with the three allocation components for calculating revenue, but it protests the inclusion of “subscriber” participating transmission owners or other PTOs in the allocation of EDAM recoverable revenue.  

The subscriber PTO model allows developers building lines to bring renewables from out of California that are not picked by the ISO’s planning process by signing up “subscribers” who will pay for the transmission line, which would be controlled by the ISO once operational. (See CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines.) 

The subscriber model is new, so none of them will have historical costs and they would not provide transmission service because the ISO does that, SCE said. 

SCE also argued the rules would provide windfalls to any subscriber PTOs just because they exist. CAISO argued it has limited the rules so subscriber PTOs will not get any undue revenue. 

FERC did not weigh in on the dispute, but having rejected a related rule in the EDAM filing, it also rejected the historical cost recovery proposal without prejudice so something could be refiled after the marketwide rules are worked out. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.) 

FERC accepted the other rules revisions, including settling transfer system resources, settling transfer revenue, settling EDAM resource sufficiency evaluation failure surcharges and enabling the net EDAM export transfer constraint. 

The Department of Market Monitoring told FERC the net export transfer constraint limits were well designed to prevent the shifting of the responsibility for load curtailment from one EDAM participant to another. The method must allow enough flexibility to cover the dynamic nature of other EDAM entities’ load and resource uncertainty, DMM said. 

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MISO Estimates 2023 Member Savings Near $5B

MISO announced last week that it saved its membership roughly $5 billion in 2023 by providing a resource sharing pool for utilities.   

Most of the estimated $3.9 billion to $5.8 billion in savings is derived from MISO members having to maintain fewer grid assets to meet peak demand versus operating as isolated utilities; it includes management of shared capacity, demand response and economical renewable generation dispatch. 

MISO said 2023 savings also stem from more efficient use of members’ existing grid assets through its energy and ancillary service markets, its reliable system management and its FERC and NERC compliance activities on behalf of members.  

MISO estimates the value it provides annually and publishes it under its Value Proposition.  

The RTO said its total benefit-to-cost ratio was 15:1 last year, up from 12:1 in 2022. Last year, MISO said it saved members $4 billion in 2022. (See MISO Says 2022 Value Proposition Tops $4B.)  

MISO said despite inflation, it expects the value of its markets and planning efficiencies to rise in coming years because it will help members navigate a “hypercomplex” system dotted with more intermittent energy sources. By 2030, the RTO said single-year benefits could conservatively range between $4.3 billion and $5.8 billion and by 2040, they could nearly triple to between $11.6 billion and $14.3 billion. 

“Although costs may continue to increase due to the current environment, MISO expects these costs to remain a small fraction of the benefits provided now and in the future,” MISO said, pointing out that it holds its cost of membership at or below inflation. 

MISO estimates that since 2007, it has saved members more than $45 billion. The grid operator said the annual benefits it delivers have increased significantly from about $600 million in 2007.   

MISO said the more substantial savings this year can be attributed to its members’ resource capacity sharing at anywhere from $2.5 billion to $4.1 billion; savings achieved through the RTO’s energy and ancillary service markets at $795 million to $878 million; and integrating renewable energy into planning at $402 million to $472 million.  

MISO’s newest value proposition comes as multiple organizations are voicing concerns that consumers aren’t realizing the full potential of possible benefits in MISO South.  

Center-right think tank R Street Institute last week said MISO South has a pattern of safeguarding its transmission constraints, resulting in utility-owned power plants that are insulated from competition with lower-cost resources.  

MISO South suffers from “overcapitalizing self-built generation and transmission … the opposite of what regional markets are supposed to accomplish,” R Street said.  

Renewables watchdog organization Energy and Policy Institute has voiced similar concerns. Both have cited a working paper from the National Bureau of Economic Research, concluding that a more integrated MISO South grid would have dropped Entergy Arkansas’ and Entergy Louisiana’s net revenues by a combined $930 million in 2022.

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FERC’s Christie Warns of ‘Very Dark Place’

NEW ORLEANS — FERC Commissioner Mark Christie brought his message of grid reliability to the Crescent City on March 4, near the site of what he says is the best college football atmosphere in the country: LSU’s Tiger Stadium at night. 

“When the sun goes down, that Tiger Stadium is a rocking environment,” Christie said. Hands down, he said, it beats the atmosphere at Alabama, Michigan, Notre Dame, Southern California and Texas. 

Dispensing with pleasantries, Christie tended to the business at hand with his keynote address to the Gulf Coast Power Association’s MISO–SPP Forum. 

“In America, we’re heading for a very dark place. We’re heading, as Franklin Roosevelt said, to a rendezvous with destiny,” he said. “Well, we’re heading, in terms of the reliability of our power grid, for a rendezvous with reality. And you can’t escape reality because ultimately, reality will track you down. And reality is tracking us down and we need an honest conversation about why we’re heading for a reliability crisis.” 

Christie has been making the rounds with his warning that dark times — figuratively and literally — lie ahead for the nation.  

Last May, he told the U.S. Senate’s Energy and Natural Resources (ENR) Committee that the grid is facing “potentially catastrophic consequences.” During an SPP forum on resource adequacy in September, he ran through a list of capacity shortfalls that grid operators are expecting and explained his use of the adjective “catastrophic.” (“Multiple-day outages [are] … catastrophic by any definition.”) (See Senators Praise Phillips, FERC’s Output at Oversight Hearing, Nation’s Grid Faces ‘Rendezvous with Reality’.) 

“It’s arithmetic. We are subtracting dispatchable resources at a pace that’s not sustainable, and we can’t build dispatchable resources to replace the dispatchable resources we’re shutting down,” he said. 

Christie said the problem is not necessarily the massive additions of intermittent wind and solar resources in many parts of the country, but rather the pace of thermal resources’ retirement. 

“We’re pushing [dispatchable resources] off the grid far too quickly for any replacement resources to take up the slack,” he said. “That’s why we’re heading for crisis. Its simple subtraction.” 

He bolstered his case by linking George Orwell and Vladimir Lenin to fellow revolutionaries MISO’s John Bear and NERC’s Jim Robb. 

Bear and Robb? 

“If you’ve ever met John Bear, he doesn’t look like a revolutionary. If you’ve ever met Jim Robb, he doesn’t look like a revolutionary,” Christie said. Referencing a quote often attributed to Orwell — “In a time of deceit, telling the truth is a revolutionary act.” He said the two CEOs are performing revolutionary acts. 

“Because why? Because they’re telling the truth,” Christie explained. “They’re telling the truth, that we are forcing dispatchable resources off the grid at a pace that simply is unsustainable, and it is going to affect our reliability.” 

Robb told the Senate ENR Committee in June that the grid’s increasing reliance on renewable resources as baseline resources retire will likely lead to “more frequent and more serious disruptions.” In MISO’s latest Reliability Imperative report released in February, Bear called for facing “some hard realities” because of “immediate and serious challenges” to the region’s grid reliability. (See Robb Warns of ‘Serious Disruptions’ from Grid Transition, MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report.)  

“What to do? Well, this didn’t come from Lenin, but it comes from where I grew up in West Virginia,” Christie said. “It’s called the first rule of holes, and the first rule of holes is when you’re in one, stop digging. So, if we’re digging a hole deeper because we’re shutting down dispatchable resources at a pace we can’t sustain, let’s stop doing it.” 

Christie’s remarks were received positively by several regulators in the audience. 

Andrew French, chair of the Kansas Corporation Commission with a background in environmental science, said he couldn’t disagree with anything Christie said. 

Andrew French, KCC | © RTO Insider LLC

“I’m an environmentalist. I come from a perspective of wanting to transition as much clean energy onto the grid as we can,” French told RTO Insider. “But, also, as a state regulator that is obviously concerned about both cost and absolutely reliability, I can’t really disagree with anything. 

“As Commissioner Christie has said before, it’s not the addition of [renewable] resources that’s the problem. It’s the subtraction of the attributes associated with some of the traditional resources that is the issue. That is the issue we have to solve,” he added. 

Marcus Hawkins, executive director of the Organization of MISO States and jaded by years of projected shortfalls that failed to materialize, shared a more nuanced perspective of Christie’s comments. 

“In MISO-land, we have a ‘boy who cried wolf’ problem” with projected shortfalls, he said. Hawkins noted OMS surveys over the past decade of the RTO’s members have consistently found shortfalls three or four years out. 

“It’s different this time. There’s load growth that’s complicating this. You need context. You can’t just go and say, “Eight gigawatts short in 2028,’ because that’s been the story since 2015,” he said. 

Marcus Hawkins, OMS | © RTO Insider LLC

Hawkins said he agreed with Christie’s comments that MISO states with vertically integrated utilities give regulators a lot of power to address reliability issues. 

“That’s what we’ve seen these last 10 years. We’ve had the gaps projected and you see the regulators work with their utilities and fill that gap,” he said. “I think we’re in a great position to continue to do that and MISO is providing more useful information to the regulators to make decisions, and that’s helpful.” 

Christie urged those listening to repeat the actions taken by Bear and others sounding the alarm on energy shortfalls. 

“You have got to be brutally honest with your state regulators, your federal regulators and policymakers about the direction that we’re heading in and the rendezvous with reality that we’re facing,” he said. “If our power supply doesn’t keep up with load, it goes out. That’s not an engineering marvel. That’s just the way it works.” 

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FERC Finds SPP Partly Complies with Order 2222

SPP’s latest attempt to comply with FERC Order 2222 has resulted in the commission’s partial acceptance and a directive to make another compliance filing. 

FERC on March 1 ordered the RTO to submit its filing by April 30 and to update the commission on implementation timeline milestones associated with the target effective date in the third quarter of 2025 (ER22-1697). 

The commission found several areas of concern with SPP’s proposed tariff revisions to comply with Order 2222’s requirements removing barriers so distributed energy resource (DERs) aggregations can participate in RTOs’ and ISOs’ capacity, energy and ancillary service markets: 

    • compensation for demand response in heterogeneous aggregations. 
    • attestation requirements for aggregators. 
    • clarity around interconnection requirements. 
    • the potential for double-counting services.  

Responding to the Missouri Public Service Commission’s request for more stakeholder engagement on the part of SPP, FERC urged the grid operator to work with distribution utilities, relevant electric retail regulatory authorities and other stakeholders to ensure its implementation process complements any state-level changes to comply with Order 2222. 

“We encourage SPP to explore use of a stakeholder group to promote transparency, and in particular, to share information about progress on the major software and process changes to core SPP systems necessary for implementation,” the commissioners wrote. 

SPP made its first compliance filing in May 2022. That August, FERC staff issued a data request advising SPP that more information was necessary to process the filing. SPP filed its response in October. 

The proceeding has drawn more than three dozen intervenors. 

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Tenn. Congressmen Introduce Bill to Make TVA IRP Process More Public

Two members of Congress from Tennessee have come across the aisle and introduced a bill that would force the Tennessee Valley Authority to make its integrated resource planning process more transparent. 

Reps. Steve Cohen (D) and Tim Burchett (R) added another “IRP” acronym to TVA’s lexicon when they introduced the TVA Increase Rate of Participation Act on March 8.  

The proposed legislation would compel TVA to establish an Office of Public Participation to oversee outreach and make recommendations to the utility to improve public accessibility and accountability.  

The representatives said their plan would “ensure the most efficient, affordable, environmentally conscious and reliable plan for meeting customers’ energy needs.” 

The office would be tasked with making sure TVA’s IRP contains more detailed information like forecasted peak demand and sales data; planned transmission investments; sensitivity analyses on fuel costs, environmental regulations, electrification and distributed energy resources; disclosure of modeling assumptions to intervening parties; and descriptions of public influence on the plan. 

Additionally, the office would be responsible for making sure the TVA Board of Directors makes decisions “approving, denying or modifying the plan, like every other utility regulator, according to the least cost and reliability requirements in the Energy Policy Act of 1992, and require consideration of resilience, extreme weather risk and public health impacts.”  

“Transparency is critical in making public policy and, for too long, TVA’s decision-making has been obscure and opaque, such as their current IRP process where organizations had to be hand-selected to participate in their working group,” Cohen, a longtime critic of TVA “secrecy,” said in a press release. “TVA needs outside guidance to meet the changing needs of utility customers as it addresses resiliency and other foreseeable disruptions to its planning,”  

Cohen made a similar statement Jan. 25 during “The People’s Voice on TVA’s Energy Plan” public hearing in Nashville that was hosted by Appalachian Voices, the Center for Biological Diversity, Southern Renewable Energy Association, Energy Alabama, Southern Alliance for Clean Energy and the Sierra Club, among others. The hearing focused on the shortcomings and shadowy nature of TVA’s IRP process and was held after the utility didn’t respond to requests to host a public hearing on its IRP. (See Nonprofits Attempt to Force a More Transparent TVA IRP Process.)  

Burchett said TVA’s customers “deserve the chance to gain insight into TVA’s decision-making process and the opportunity to offer input.”  

“I appreciate the ways TVA has made an effort to become more transparent in recent years, and this would provide some solid guidelines on how to make that even more of a reality,” he said.  

TVA is conducting its first long-term IRP effort since 2019. The plan not only will guide near-term resource decisions, but steer long-term programs that will determine how the region’s electricity needs will be met through 2050. 

TVA: More Public Engagement to Come

TVA spokesperson Scott Fiedler characterized the federal agency as a “transparent organization that actively seeks public input on and about our decision-making processes.” He said TVA “intentionally seeks out, engages and welcomes a diverse set of voices” in its IRP process.   

“We are currently reviewing the legislation that was introduced today. We believe we have good methodology, but TVA is always open to improving our public input processes,” Fiedler said in an emailed statement to RTO Insider.  

TVA said it will release a draft IRP later in March for public comment. From there, the utility has committed to holding two virtual open houses on the IRP in addition to a series of in-person open houses in Tennessee, Alabama, Mississippi, Kentucky, Georgia, North Carolina and Virginia.  

“This will help ensure that every member of the public will be able to receive information and ask questions and provide feedback,” Fiedler said. “Moving forward, with public stakeholders, TVA is creating a roadmap that will support TVA’s mission of making life better for everyone in the region.” 

TVA kicked off its IRP process last spring and said it began the planning by soliciting public input on considerations for the 2024 IRP. The IRP is evaluated by a nonpublic, invitation-only working group TVA formed, composed of representatives of “local power companies, academic institutions, environmental organizations, state government and other community groups,” according to TVA. The working group reviews the federal utility’s inputs, assumptions and results; TVA posts short summaries of the working group’s meetings to its IRP site.  

Nonprofits Say Law is Overdue

Several environmental and advocacy groups applauded the legislation’s introduction.  

Vote Solar Southeast Regulatory Director Jake Duncan called the TVA Increase Rate of Participation Act “a long-overdue yet monumental stride toward creating a meaningful, transparent and inclusive energy plan for the TVA.” 

“We applaud Congressman Cohen and Congressman Burchett for their leadership in ensuring TVA’s power system planning includes the very people these decisions impact,” Appalachian Voices’ Bri Knisley said.  

Sierra Club Tennessee Field Organizing Strategist Amy Kelly said TVA has operated for too long without “meaningful public and expert engagement during their energy planning.” 

“TVA was founded as a public utility to enrich and benefit the people, industries and environment of the Tennessee Valley, and this legislation would help TVA live up to its mission,” she said. 

The Southern Alliance for Clean Energy (SACE) also has criticized TVA for carrying out “one of the least public IRP processes in the nation” despite being the nation’s sole federally owned utility.  

“This emboldens TVA to invest in new fossil fuel infrastructure, which will expose people in the Tennessee Valley to the risks associated with higher bills, more carbon pollution and more power outages in the future,” SACE said in a statement February. 

By all appearances, TVA will replace two coal units at its 2,470-MW Cumberland Fossil Plant with a 1,450-MW natural gas plant. Early this year, FERC approved a pipeline meant to feed the plant, although TVA has said its decision to build the gas plant isn’t final. (See FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant and TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.) 

SACE has criticized TVA for using the minimum required public engagement outlined in the National Environmental Policy Act as a substitute for comprehensive public interaction. 

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Conservation Groups File Another Lawsuit to Stop Cardinal-Hickory Creek’s Last Mile

Three conservation groups have filed a new civil suit against three federal agencies for consenting to permits and a land exchange that allow the divisive Cardinal-Hickory Creek 345-kV line to carve a final, mile-long path through a protected wildlife refuge in Wisconsin.  

The Environmental Law and Policy Center filed the complaint in the U.S. District Court for the Western District of Wisconsin on behalf of the Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association.  

The three allege the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated the National Environmental Protection Act (NEPA), National Wildlife Refuge System Improvement Act of 1997 and Administrative Procedure Act by approving permits and allowing a land exchange to assemble the final mile-long stretch of the 102-mile, $650-million transmission line through the Upper Mississippi River National Wildlife and Fish Refuge. 

Co-owners ITC Midwest and Dairyland Power Cooperative late last month finalized an agreement with the Fish and Wildlife Service to turn over about 36 acres of privately owned land along the Mississippi River in Wisconsin for refuge annexation while receiving about 20 existing acres of the refuge near the Iowa state border.  

The conservation groups accused federal agencies of “skewing the required NEPA review and purpose and need statements to avoid rigorously exploring and objectively evaluating all reasonable alternatives.” They also said the east-west 200-foot transmission towers will interrupt a “major north-south migratory bird flyway used by hundreds of thousands of birds annually.”  

“The transmission companies did not evaluate alternative crossings outside of the refuge in their environmental impact statement, and we should not set a precedent that a simple land swap is all it takes to plow through a national treasure,” Driftless Area Land Conservancy Executive Director Jennifer Filipiak said in a press release.  

Wisconsin Wildlife Federation President Kevyn Quamme said a “massive transmission line crossing through this area will be harmful to the important habitats for fish and wildlife in the refuge and to the millions of migrating birds that pass through on the Mississippi Flyway each year.” 

“Building a transmission line through the refuge also will serve as a deterrent to locals and tourists alike who visit the refuge and contribute to the local economy,” Quamme added. 

Cardinal-Hickory Creek is the final piece of MISO’s 17 Multi-Value Projects approved as a $5 billion portfolio in 2011. The line is estimated to facilitate the connection of nearly 20 GW of renewable energy and has been mired in litigation for more than a decade. 

The newest lawsuit concerning Cardinal-Hickory Creek is related to a federal district court decision issued in 2022 that halted construction on the final line segment, finding that federal agencies violated federal law when they cleared the line to route through the refuge. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.) Last summer, the Seventh Circuit U.S. Court of Appeals vacated the decision and lifted the injunction, finding that the Fish and Wildlife Service at the time hadn’t issued a final permit for the utilities to build across the refuge.  

The Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association said Cardinal-Hickory Creek’s developers were warned in the 2022 ruling against them that stringing lines right up to the protected wildlife refuge would be staging an “orchestrated train wreck.”  

‘Weaponizing NEPA’

Co-owners ITC Midwest and Dairyland Power Cooperative said they were “dismayed” by the latest litigation and said the lawsuit could counterintuitively “delay significant environmental benefits” to the Upper Mississippi River National Wildlife and Fish Refuge.  

The two said the deed exchange stands to expand the refuge when the line is completed. They said an analysis from the Fish and Wildlife Service found that “the proposed land exchange fulfills the refuge’s purposes by exchanging lower-quality habitat for higher-quality habitat, increasing the total protected acreage in the refuge, reducing habitat fragmentation in the long term and allowing the refuge to acquire a high-priority tract that would not otherwise be available.” The Fish and Wildlife Service also said that in the long run, the land swap will supplement the refuge’s breeding grounds.  

ITC and Dairyland said the refuge land they want to use to cross the Mississippi River is adjacent to a road and farmland and has “low habitat value.” They also said construction of Cardinal-Hickory Creek would allow them to deenergize and remove an existing 161-kV line that cuts through the refuge. The Fish and Wildlife Service deemed that a net conservation benefit because it also would increase the protected acreage and cut down on the number of transmission towers in the refuge overall. 

ITC and Dairyland said they’re committed to minimizing impacts to grass habitats, scrub and wetlands, and they pledged to not grade land inside the refuge. They said they’re offering to nearly double the refuge’s land tradeoff for a transmission project that is “vital to the future of our region’s renewable energy and clean energy economy.” 

“As of October 2023, there are 161 renewable generation projects in Wisconsin, Iowa and other Upper Midwestern states representing more than 24.7 GW dependent upon its completion — enough to power millions of homes and businesses with clean energy,” the two said. 

The companies also said the continued litigation over Cardinal-Hickory Creek is delaying its in-service date and driving up costs. They accused the conservation groups of “weaponizing NEPA” and said the Environmental Law and Policy Center should be in favor of the line because it supports a clean energy economy.    

“Over the past few years, several of these same opponents have filed multiple lawsuits in federal and state court trying to stop construction of the project. The co-owner utilities have successfully navigated four separate injunctions and won appeals before the Wisconsin Supreme Court, as well as three different favorable opinions from the U.S. Seventh Circuit Court of Appeals,” ITC and Dairyland said.  

They referenced a county circuit court judge’s decision last year to uphold the Wisconsin Public Service Commission’s 2019 decision to issue a certificate of public convenience and necessity for the line, as well as a 2022 ruling from the Wisconsin Supreme Court that a former state regulator’s years’ worth of encrypted messages to the line developers’ employees did not amount to a serious risk of bias during permitting. (See Wisconsin Tx Project Clears State Litigation; Wisconsin Court Undercuts Lawsuit in Cardinal-Hickory Creek Dispute.)  

Co-owners ATC, ITC Midwest and Dairyland Power Cooperative report that Cardinal-Hickory Creek is more than 95% complete. The eastern half of the line was placed into service in early December.  

ITC Midwest said it expects construction on the western half of the project from the Hickory Creek Substation in Dubuque County, Iowa, to the Hill Valley Substation in Wisconsin to be finished and the line in service by June. ITC said the segment is virtually complete except for a 2.2-mile stretch extending from a spot near the Nelson Dewey Substation in the village of Cassville, Wis., westward across the Mississippi River to a spot near the Turkey River Substation in Clayton County, Iowa. That portion of the line includes the route through the refuge.  

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NJ Bill Would Levy Annual Fee on EV Ownership

New Jersey’s Assembly Transportation and Independent Authorities Committee on March 7 backed a bill that would levy a $250/year fee on electric vehicle registration beginning in July, brushing aside criticism from car sellers and environmental groups that it would be excessive. 

The fee is part of wide-ranging bill A4011, which would amend the law governing the state’s Transportation Trust Fund Authority, which raises funds to pay for transportation investment projects and mass transit. The bill, sponsored by Democrats in both the Assembly and Senate, would reset the fund’s revenue system from 2025 to 2029 to help meet state capital initiatives. 

The initiative comes as states across the U.S. are wrestling with how to raise funds for infrastructure projects that have traditionally been funded through a gas tax as drivers shift from fossil-fueled vehicles to EVs, cutting gas consumption and gas tax income. 

Annual fees on EV ownership are now levied in 30 states, with the highest fee levied in Washington at $225, with Georgia charging $211 and Alabama charging $203, according to a report by Money in August 2023. 

New Jersey’s would start at $250 on July 1 and rise by $10 every year until it reaches $290 on July 1, 2028. The fee would be paid when the vehicle is initially registered and when it is renewed. 

Environmental groups said they have no problem with a fee on EV buyers but that the proposed level was way above what would be fair. 

Speaking for ChargEVC, which seeks to advance the EV market through the development of sustainable programs and policies, Gabel Associates’ Eve Gabel-Frank said the fee would be “punitive” and the “highest fee in the country.” 

She said that under the bill, an owner of the hybrid Toyota Prius Prime would pay $97 in gas taxes a year, while an owner of the Honda CR-V, a small SUV, would pay $127. 

“So paying a $250 fee is way higher. They’d actually be paying double” what an owner of an efficient, gas-powered vehicle pays, Gabel-Frank said, suggesting the committee cut the fee to $75. 

EV advocates argue that New Jersey’s proposed $250 registration fee for EVs would be more than the gas taxes gas-powered cars pay. | ChargeEVC

But Eric DeGesero, speaking for the Fuel Merchants Association of New Jersey, said the fee should actually be higher. He said the average vehicle uses 569 gallons of gas a year, which generates about $245 from the state gas tax of 43 cents per gallon. 

“The fee should be rounded up to $300, set there immediately and adjusted annually,” he said. 

‘Pay Their Fair Share’

Business groups and unions broadly supported the bill, saying the resulting capital investments would create jobs and stimulate economic development in the state. 

Steven Gardner, director of the New Jersey Laborers Employers Cooperation and Education Trust, said transportation is essential to the state, and as it transitions to EVs, it needs to look at new ways of raising revenue. He noted that in a sign of the shift, Gov. Phil Murphy’s administration in November adopted the Advanced Clean Cars II rules, which require zero-emission vehicles to account for all vehicles sold by 2035. 

“This legislation begins to include the fee on zero-emission vehicles to ensure they begin to pay their fair share for the roads they also drive on,” he said. “Without a trust fund making consistent investments, none of us could get to our jobs, our children’s schools, the shore or any of our state parks. New Jersey’s entire economy is wholly dependent on having a first-class transportation network.” 

Voting 7-4 in favor of the bill, largely along party lines, committee members focused their comments mainly on the gas tax and need for infrastructure investment and how to achieve it, paying little heed to the EV fee issue. A similar bill in the Senate has not advanced. 

Aside from the EV fee, the bill would enable the fund to raise revenue by gradually increasing the target income from 2025 to 2029 and setting the gas tax rate at a level to meet that target. The income target would start at $2.032 billion in 2025 and rise by about 16% to $2.36 billion in 2029.The revenue raised would go into a general capital reserves fund to support capital projects, but the bill also specifies that it can’t be used to pay debt service on bonds. 

‘False Narrative’

Opposing the bill, Gabel-Frank sought to correct what she said is a “really common false narrative” — and one put forward by DeGesero — that EVs are heavier because of their batteries than a gas-powered vehicle. 

In that argument, the weight of the EVs would cause more road damage, which would need to be repaired with transportation investment funds. 

“We did a review of studies,” Gabel-Frank said. “We found that road damage is not caused by passenger vehicles. It’s caused by vehicles that are over 26,000 pounds” — heavy-duty trucks. 

Doug O’Malley, director of Environment New Jersey, said the fee — along with Murphy’s recent proposal to remove the exemption for EV buyers from paying the state’s 6.25% sales tax — would hurt the consumer uptake of ZEVs. 

Jim Appleton, president of the New Jersey Coalition of Automotive Retailers, said his members are “all in on EVs,” but the fee would “make it more difficult for dealers to turn EV-curious consumers into EV owners.” 

“No one disputes the idea that EV drivers must pay their fair share to maintain roads and bridges,” he said. But “New Jersey cannot achieve higher EV adoption without generous cash-on-the-hood incentives and sales tax incentives.” 

“We have conflicting policies at play here. If we’re going to ask EV drivers to pay into the Transportation Trust Fund — and we should — we shouldn’t make them pay for it all upfront in the showroom,” Appleton said. “What we’ve got to do is try to come up with a way that avoids EV buyers having to come up with that extra $1,000 at the point of purchase.” 

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Can US Maintain Record Solar, Clean Power Growth?

The U.S. could nearly quadruple solar capacity in the next 10 years, from the 177 GW installed at the end of 2023 to 673 GW by 2034, with solar providing the largest share of the nation’s electricity generation by 2040, according to a report released March 6 by the Solar Energy Industries Association and Wood Mackenzie.

But such exponential growth could depend on the right mix of policy and market conditions, SEIA and WoodMac caution in the report. In a “bull” scenario ― with few supply chain or interconnection constraints, and stable financing and access to tax credits ― an additional 85 GW of solar could be installed by 2034, the report estimates. But a less solar-friendly “bear” scenario could cut new capacity over the next decade by nearly 120 GW.

solar

By 2030, the U.S. could be installing 50 GW of residential, commercial and utility-scale solar per year. | Wood Mackenzie

The result, the report says, is that “there could be a 200-GW swing in solar installations over the next decade. … The challenges that currently limit growth in this industry ― particularly transmission and interconnection limitations ― will only become more heightened over time. Addressing these limitations is key to meeting both decarbonization goals and growing power demand.”

The more immediate effects of those limitations are detailed in a second report, the American Clean Power Association’s (ACP) 2023 Annual Market Report, released March 7. Over the past three years, delays on solar, wind and storage projects have put more than 60 GW of clean power capacity on hold, the report says.

On the upside, the pipeline of clean power projects is healthy, with close to 71 GW of projects under construction by the end of 2023 and close to 100 GW in advanced development, meaning they have a firm equipment order and a power purchase or offtake agreement or other utility contract.

“The clean power pipeline experienced a 26% year-over-year growth from 135,221 MW at the end of 2022,” the ACP report says.

The two reports provide slightly different but complementary perspectives on the banner year clean power, especially solar, had in 2023. (All figures in the SEIA-WoodMac report are DC; the ACP report does not specify DC or AC.)

    • Tracking only utility-scale projects over 1 MW, the ACP report says 33.8 GW of clean power — solar, wind and storage — came online in 2023. SEIA and WoodMac count 32.4 GW of residential, commercial and utility-scale solar projects combined. Both reports have solar at 58% of new power generation added to the U.S. grid.
    • Both reports also put Texas in the No. 1 spot for new solar and clean power. On solar only, Texas and No. 2 California are neck and neck: 6,533 MW vs. 6,171 MW, respectively. But, counting solar, wind and storage, Texas leaves California in the dust: 9,931 MW to 5,590 MW.
    • According to ACP, Texas and California together put more new clean power on the grid last year than the next 19 states combined.
    • The ACP report also underlines the mainstreaming of clean power, with maps showing that every state in the union has some clean power. Wind energy provides more than 20% of electricity in 12 states, and solar delivers more than 10% of electricity in nine. The only state on both lists is Maine.
    • More clean power than natural gas has been added to the grid every year since 2014, but natural gas also had a banner year in 2023, with 8,999 MW of new capacity coming online, a 27% increase over 2022, according to ACP.

The NEM 3.0 Effect

While both reports see solar as the dominant form of generation going forward, SEIA and WoodMac see some clouds on the horizon. Record installations notwithstanding, solar in general has been affected by higher interest rates and supply chain, interconnection and workforce challenges.

The residential solar market installed a record-breaking 6.8 GW in 2023, but a downturn is expected this year, primarily because of California’s introduction of much lower compensation rates for the power rooftop solar owners put back on the grid.

solar

ACP reports more than 170 GW of solar, wind and storage projects either under construction or in advanced development. | American Clean Power Association

The new compensation plan — referred to as Net Energy Metering 3.0 — goes into effect in April and is especially disadvantageous for homeowners who only install solar panels, rather than solar and storage. Residential installations in California remained high through the first three quarters of 2023, as installers worked through a backlog of orders that would qualify for the previous, higher compensation, NEM 2.0.

But residential installations in the Golden State dropped 35% in the fourth quarter, and WoodMac says both high interest rates and the transition to NEM 3.0 will drive a 13% decrease in new residential capacity across the country this year. The California market could contract 40%.

Commercial solar could also feel a pinch from NEM 3.0, although a backlog of installations in California has been keeping figures high. This sector includes distributed projects with industrial, commercial, agricultural, school, government or nonprofit customers, and put 1,851 MW of new power on the grid in 2023, a 19% increase over 2022.

The report sees a dip coming in 2025 through 2027, again from NEM 3.0, but also from added costs related to the Inflation Reduction Act. To qualify for the law’s full 30% investment tax credit, commercial projects over 1 MW will have to pay prevailing wages and work with registered apprenticeship programs.

The extent of the impact here will depend on the final rules of the ITC, expected later this year.

The utility-scale solar sector ended 2023 on a record-breaking high note with 10.5 GW installed in the fourth quarter. But President Joe Biden’s two-year moratorium on tariffs on solar cells and panels from Cambodia, Malayasia, Thailand and Vietnam ends in June, which could result in higher prices and tighter supply chains.

WoodMac also notes that “high interest rates, tighter financing condition and interconnection uncertainty slowed contract negotiations,” which resulted in the utility-scale project pipeline falling to a record low of 83 GW.

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NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance

The NEPOOL Participants Committee on March 7 unanimously approved ISO-NE’s package of tariff revisions to comply with FERC Order 2023. 

ISO-NE expects to submit the compliance filing April 1, two days before the deadline set by FERC in its efforts to unclog interconnection queues that have bogged down nationwide. 

The vote follows months of deliberations that included a Feb. 15 NEPOOL Transmission Committee meeting at which an initial proposal, as well as six proposed amendments to it, failed to gain the two-thirds support needed for approval. (See ISO-NE Order 2023 Compliance Proposal Fails to Pass NEPOOL TC.) 

ISO-NE incorporated several elements of the amendments into the final package, which was approved with only two abstentions. 

The RTO summarized the post-Feb. 15 changes to the package in a March 1 memo to the committee: 

    • An interconnection customer may specify in its interconnection request for capacity network resource (CNR) interconnection service that the requested service be downgraded to network resource interconnection service under certain conditions. 
    • After the completion of a cluster study (not including the transitional cluster study), if the RTO determines that a cluster restudy is required (because of the withdrawal of other projects), the developer of a remaining project may request a specific one-time decrease in the size of the generating facility or elective transmission upgrade for the restudy. 

For customers with assigned queue positions as of 30 calendar days after April 1, but for which system impact studies are projected to be completed between May 1 and June 30, the RTO will still tender transitional cluster study agreements. However, if the SIS is complete and accepted by the customer by July 1, the request will no longer proceed to the transitional cluster study. Instead, the customer will be tendered an interconnection agreement pursuant to the applicable provisions in the respective interconnection procedures. 

    • Where a request successfully participates in the transitional CNR group study and then later obtains a capacity supply obligation in the Forward Capacity Market, the rules governing any termination of the CNR capability will be governed by the relevant FCM rules. 

“Importantly, each of these additions can be incorporated without adding to the overall time frames or decreasing the efficiency of the new process,” ISO-NE said. 

When FERC issued Order 2023 last July, the potential capacity of projects waiting in interconnection queues exceeded 2 TW, more than the amount of generation already online nationwide. It seeks to streamline the interconnection process for transmission providers, provide greater timing and cost certainty to interconnection customers and prevent discrimination against the wave of renewables being proposed nationwide. (See FERC Updates Interconnection Queue Process with Order 2023.)

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NV Energy OK’d for Coal Plant Conversion, Solar+Storage Project

Nevada regulators approved NV Energy’s plan to convert its last coal-fired power plant to natural gas, while also allowing the company to move forward with a $1.5 billion, 400-MW solar-plus-storage project. 

Approval of the solar-plus-storage project, known as Sierra Solar, may allow the utility to reduce an open position that’s been described as one of the largest in the West. NV Energy is developing the project, which would be about 15 miles northeast of Fernley in northern Nevada. 

But whether Sierra Solar will be built remains to be seen. 

In an order approved March 1, the Public Utilities Commission of Nevada (PUCN) set conditions on Sierra Solar including payment of damages to ratepayers if the project is delayed or doesn’t perform as expected. 

The order admonished NV Energy for arguing that it needed to move forward quickly with the project, then balking at conditions. It quoted NV Energy’s response when asked about a maximum project cost: “If the commission … feels like it has to have an upper limit on costs, we’ll assess if we think it’s reasonable and whether we can move forward with the project or not.” 

“The commission is persuaded that there is a resource adequacy need necessitating consideration of the Sierra Solar project now and is troubled by the suggestion that this need may be ignored unless NV Energy gets the terms that it desires for the Sierra Solar project,” the commission wrote in its order. 

In a news release after the commission’s vote, NV Energy said it “is diligently reviewing the conditions the commission placed upon the project.” 

Planning Process Questioned

NV Energy proposed the Sierra Solar project through the fifth amendment to its 2021 Integrated Resource Plan. The amendment also proposed the conversion of the North Valmy Generating Station, NV Energy’s last coal-fired plant, to run on natural gas through 2049. 

PUCN largely approved the amendment, despite objections of stakeholders who said the projects should go through a more comprehensive evaluation as part of the utility’s 2024 IRP that will be filed this year. 

Instead, the utility has resorted to “crisis planning” through multiple amendments to the IRP, said Emily Walsh, clean energy policy adviser at Western Resource Advocates. Walsh noted that the cost of projects proposed in the fifth amendment far exceeded that of projects in the 2021 IRP. 

“They’ve really been gaming the IRP process,” Walsh told RTO Insider. 

In addition to approving Sierra Solar and the North Valmy conversion, the commission authorized a 2049 retirement date for two gas-fired units at the Tracy power plant, which had been scheduled for closure in 2031. 

But the commission declined to approve an asset purchase agreement for future development of the 149-MW Crescent Valley solar-plus-storage project about 50 miles from the Valmy plant. Because the project is at an early stage, the utility can bring the proposal back as part of its 2024 IRP, the commission said. 

Open Position

One of the drivers behind NV Energy’s proposals was to reduce its open position — resource needs that are met through short-term market purchases rather than by utility-owned resources or long-term contracts. 

In a survey of 13 Western utilities, NV Energy’s projected open position in 2025 was 1,092 MW, second only to that of PacifiCorp’s 1,637 MW, according to testimony filed with PUCN on behalf of the utility. As a percentage of peak demand, NV Energy’s open position was 13%, ranking sixth out of the 13 utilities. 

Proposals in NV Energy’s IRP amendment would reduce its open position to 820 MW in 2026, representing 10% of peak demand. 

The commission’s order also addressed NV Energy’s participation in the Western Resource Adequacy Program, directing the utility to postpone its financially binding season from winter 2026/27 to winter 2027/28.  

“NV Energy’s [forecast] open position for the summer of 2027, with or without commission approval for the requests in this docket, would subject NV Energy to substantial penalties that could be passed on to ratepayers,” the commission wrote. 

Valmy Solution

In its 2021 IRP, NV Energy planned to replace capacity from the coal-fired North Valmy Generating Station with the Iron Point and Hot Pot solar-plus-storage projects. The utility plans to end coal combustion at Valmy by the end of 2025. 

But supply chain issues derailed the solar projects, according to the utility, which then proposed a 200-MW battery storage project as a partial solution for the Valmy retirement. The commission rejected the proposal, asking NV Energy to come back with a complete solution for Valmy. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.) 

In its March 1 order, the commission approved the plan to convert Valmy to natural gas but granted only $50 million of the $83 million NV Energy wanted for the project. 

The $50 million is NV Energy’s actual costs for the project, the commission said, while the remaining $33 million is “just a placeholder amount associated with upgrades that may be needed at some point in the future.” 

NV Energy plans to split the cost of the Valmy conversion with Idaho Power, which is 50% owner of the plant. 

NV Energy acknowledged that it initially didn’t consider a gas conversion for Valmy. But a new transmission study found that an area called the Carlin Trend needs voltage support from a firm dispatchable resource. 

The commission said the Carlin Trend constraint is “a real condition.” In addition, “without Valmy, there is a high probability Nevada would have experienced rolling blackouts three out of the last four years,” the commission stated in its order. 

Once NV Energy’s Greenlink West transmission line is completed, the Valmy plant may be able to run less often, the commission noted.