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October 7, 2024

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NJ Cuts Incentives for New Phase of EV Promotion

New Jersey on Monday launched the third phase of its Charge Up New Jersey electric vehicle (EV) subsidy program, cutting the maximum vehicle incentive to $4,000 but adding a new $250 subsidy for home chargers.

State officials said the incentive would apply to EV purchases beginning July 25 and would remain available until the $35 million in funding is exhausted. They also said they would begin accepting applications for three other programs that offer incentives to promote the use of EVs. Those programs pay for the installation of charging stations in tourist areas and multi-dwelling properties and help local and state governments add EVs to their fleets.

Speaking at a press conference in Asbury Park, Gov. Phil Murphy said the program, shows “our continued commitment to transitioning our economy away from fossil fuels.

“We know this incentive can push more buyers to making the decision to go electric,” said Murphy. The incentives will be especially effective, he said, “as the prices of EVs continue to fall more and more in line with gas-powered cars, especially in the all-important and growing mid-price category.”

The first two phases of Charge Up New Jersey, which is run by the Board of Public Utilities, assisted the purchase of about 13,000 vehicles.

Seeking ‘Incentive Essential’ Buyers

The new $250 incentive will be available for Level-Two chargers capable of capturing data, known as “smart” or “networked” chargers. The incentive will pay for chargers installed in a residence and will only cover equipment, not installation costs. The state budget approved in June allocated $5.5 million for the incentives.

At the same time, the BPU reduced by $1,000 the maximum EV incentive, from the $5,000 offered in the second phase. As before, the maximum incentive is only available for vehicles that cost $45,000 or less. Vehicles priced between $45,000 and $50,000 are eligible for an incentive of up to $2,000, and no subsidy will be awarded for higher priced vehicles.

The incentive is calculated by multiplying $25 by the number of miles that the vehicle will run on a single charge. For example, a 2021 Hyundai Kona Electric, which can run for about 258 miles on a single charge, according to the U.S. Environmental Protection Agency’s fueleconomy.gov site, would be eligible for the maximum $4,000 incentive.

The BPU implemented the $45,000 price-tag cap in the second phase after data showed that Tesla vehicles received 83% of the incentives in the first phase. The reduction meant that in the second phase only the lowest priced Tesla could get the maximum incentive. BPU officials said they believed that change would help the program focus on “incentive essential” customers: those who would only buy an EV if there was an incentive available. (See NJ Boosts EV Charging Program for Tourist, Multifamily Locations.) Indeed, data from the second phase show that Teslas accounted for 66% of the incentives granted.

Murphy noted that the available funds were quickly exhausted in the first two phases of the program.

“We expect more of the same this year,” Murphy said. “And with a refocusing of this incentive for mid-priced vehicles, we believe we can expand the appeal of an electric vehicle to more consumers.”

Expanding Charger Numbers

The EV incentive is part of a portfolio of programs aimed at helping the state meet the goals set out in the Energy Master Plan for the state to deploy 330,000 light-duty EVs on the road by 2025.

Slightly more than 64,000 EVs were registered to drive on New Jersey roads at the end of 2021, and there are about 750 chargers in the state.

The state in January 2020 enacted a law that called for the installation of at least 400 DC fast chargers, which can add about 60 to 80 miles to an EV in 20 minutes of charging, and 1,000 Level 2 chargers, which add 10 to 20 miles per hour of charging time, by Dec. 31, 2025.

New Jersey officials say the key to putting more EV vehicles on the road is to have more chargers available.

“We don’t want anybody to say ‘I’m not buying an electric vehicle because there’s not enough charging stations,” said BPU President Joseph L. Fiordaliso at the conference Monday.

To that end, New Jersey’s budget struck in June allocated $10 million to support the purchase of EVs by state and local governments, $6 million to put chargers at tourist sites and $4 million to put them in multi-unit dwellings.

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Newsom Calls for ‘Bolder’ Climate Action in California

The state agency drawing up California’s plan to reach carbon neutrality by 2045 should take “even bolder action” to address climate change, Gov. Gavin Newsom said on Friday.

The California Air Resources Board (CARB) should include in its climate plan a goal of at least 20 GW of offshore wind by 2045 and a target of 7 million “climate-friendly” homes in the state by 2035, Newsom said. The state has about 14.5 million housing units, according to census data.

Newsom said he’s asking state agencies to plan for a clean energy transition without new natural gas plants. And he asked CARB to set a carbon removal goal of 20 million metric tons (MMT) for 2030 and 100 MMT for 2045.

“We know from the Intergovernmental Panel on Climate Change that there is no path to carbon neutrality without carbon capture and sequestration,” Newsom said in the letter sent to CARB Chairwoman Liane Randoph.

CARB lays out a roadmap for the state to meet its climate goals in a document called the scoping plan. Under state law, the scoping plan must be updated every five years. The next edition is due by the end of this year.

A draft version of the scoping plan was released in May and presented to the CARB board last month. Although CARB analyzed ways to get the state to carbon neutrality by 2035, the draft plan’s selected scenario has the state reaching carbon neutrality in 2045. Some critics have called the proposed scoping plan “too little, too late.” (See Critics Tear into CARB Draft Climate Change Plan.)

‘More Aggressive Actions’

In his letter to Randolph, Newsom called the draft plan “the world’s first large-economy plan for carbon neutrality.” He said CARB’s final scoping plan must lay out a path to statewide carbon neutrality by 2045 as well as meeting the state’s 2030 climate goals. California’s 2030 target is a 40% reduction in greenhouse gas emissions compared to 1990 levels.

“The state’s draft carbon neutrality road map doesn’t go far enough or fast enough,” Newsom said Friday in a release. “That’s why I’m pushing state agencies to adopt more aggressive actions, from offshore wind to climate-friendly homes, and to make sure we never build another fossil fuel power plant in California again.”

Newsom asked that CARB incorporate his goals into the scoping plan.

Regarding offshore wind, Newsom said he would ask the California Energy Commission to set 20 GW by 2045 as a planning goal. Earlier this year, CEC proposed offshore wind goals of 3 GW by 2030 and 10 to 15 GW by 2045 —targets that some stakeholders called too conservative. (See CEC Postpones Vote on Offshore Wind Goals.)

‘Going Big’ on OSW

Offshore Wind California, a trade group of offshore wind developers and technology companies, is urging the CEC to approve offshore wind planning goals of 5 GW by 2030 and at least 20 GW by 2045. The group said Friday that Newsom’s announcement was “great news.”

“This is another sign California is serious about ‘going big’ on floating offshore wind, to drive economies of scale and realize the very substantial clean power, climate and jobs benefits offshore wind can deliver for our state,” Adam Stern, the group’s executive director, said in a statement.

In another request, Newsom wants CARB to adopt a 20% clean fuels target for the aviation sector.

Newsom also asked CARB to work with the state’s Geologic Energy Management Division (CalGEM) to form a task force to find and fix methane leaks from oil infrastructure near communities.

The governor noted that the state budget allocates $100 million for methane detection satellites plus another $100 million for CalGEM to plug orphan oil wells, which may be leaking methane.

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NERC Report Highlights Dangers of Tower Climbing

In a new Lessons Learned report posted Wednesday, NERC reminded utilities to be vigilant about the possibility of unauthorized people climbing on their transmission towers.

The Tower Climber Incident report is based on an incident in which a climber ascended to the top of a transmission tower before being detected by the transmission operator (TOP). As is usually the case with Lessons Learned reports, many details of the event — such as its location and the people, utilities and regional entity involved — were omitted to protect potentially sensitive business information. NERC also left out the date of the incident, only stating that it occurred “on an August day.”

Unapproved climbers on transmission towers are an ongoing concern in the U.S., with multiple incidents reported in the last year. In January, Duke Energy had to cut power to more than 15,000 customers after a man climbed an 85-foot tower in Charlotte, N.C., and stayed there for nearly four hours. In addition, The Washington Post reported last August on police in Utah finding hammocks strung high on transmission towers operated by Rocky Mountain Power, though without finding the trespassers themselves.

In the event detailed in NERC’s report, the TOP received a report of a “civilian tower climber” in a 230/500-kV corridor and dispatched a line crew to investigate. The crew was joined at the site by police and emergency services; after receiving confirmation of the report, the TOP relayed it to the reliability coordinator; together with the RC, the TOP decided to remove the three circuits that shared the tower (500 kV, 230 kV and 115 kV) from service to avoid injuring the climber.

To safely shut down the circuits, the RC first ordered import schedules on a nearby interface curtailed to 53% (later 21%) of their value prior to the incident. Internal generation was increased, and all load rejection schemes for the area were armed. The TOP then “reduced the load on the transformers supplied by these circuits” before removing them from service.

Meanwhile, the field crew worked to prepare a clearance so a crane could access the tower. After more than two hours, rescuers were able to bring the climber down, at which point police took the climber into custody. At this point the RC and TOP began to bring the circuits back online, after which the RC rescinded the emergency measures for the area.

Reviewing the incident, NERC noted that climbing a transmission tower poses “a safety hazard to the climber, operational risks to the entity and a potential service loss to consumers.” Its recommendations for TOPs and transmission owners included following policies on the installation of deterrents to prevent climbing; immediately after the event, the TOP had discovered there were “no visible danger/warning signs” in the area, which it addressed immediately.

NERC also suggested that TOs and TOPs ensure they have policies on responding to public safety hazards and communicating with other stakeholders, including first responders in addition to the RC, and that they “establish a minimum above-grade height for tower climbing aids that discourages unauthorized climbing.”

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NARUC Weighs SCOTUS Decision’s Impact on Coal

SAN DIEGO — The Supreme Court’s recent decision in West Virginia v. EPA and its potential effects on the nation’s coal-burning power plants occupied a session on EPA’s authority over CO2 emissions at the National Association of Regulatory Utility Commissioners Summer Policy Summit.

NARUC’s Subcommittee on Clean Coal heard from attorney Matthew Leopold, who helped lay the legal groundwork against the EPA in the West Virginia case during a discussion moderated by West Virginia Public Service Commission Chair Charlotte Lane.

The high court’s 6-3 decision on June 30 ruled that EPA lacks authority to compel generation shifting to reduce carbon emissions, saying the agency failed to provide “clear congressional authorization” for the rulemaking. (See Supreme Court Rejects EPA Generation Shifting.)

While environmentalists decried the decision, Lane called it “exciting” given the push to retire coal plants.

“We all need to work together to make sure [EPA] regulations do not cause grid reliability problems, or make electricity less affordable for ratepayers,” she said.

Leopold, a former EPA general counsel during the Trump administration and now a partner at law firm Hunton Andrews Kurth, said the decision checked but did not fundamentally alter EPA’s ability to regulate greenhouse gases from power plants under the Clean Air Act.

Yet the decision could have far-reaching effects on federal agencies’ rulemaking, he said. It invoked the major questions doctrine, a rarely cited legal principle affecting Congress’ delegation of authority to executive agencies, to say the EPA had overstepped its bounds.

Going forward, courts will scrutinize EPA and other agencies’ actions to ensure they have a clear basis in statute and historical precedent, Leopold said.

“If an agency’s getting out of its lane, and it’s trying to do something that hasn’t historically done, it may be under threat,” he said. “And so, the example right now on the Biden administration’s list of big rules … is its [approach] to climate change that a lot of lawyers, including myself, are saying might be vulnerable.”

He cited a proposed rule requiring that public companies disclose business risks related to the climate and greenhouse gas emissions to the Securities and Exchange Commission.

“There, you have similar facts [to West Virginia v. EPA because] … the SEC has not regulated climate change since [the agency began in] the 1930s,” he said. The rule would be a “new transformative approach that [the SEC has] never done before. There’s no express discussion of environmental regulation in their statutory authority. And so, I think, you know, the administration is going to have to look long and hard about how they go about finalizing that rule.”

“More to the point and more practical, is how this decision is going to affect fossil-fired and coal generation,” Leopold said.

The case calls into question whether the EPA can require emissions controls only at the source power plant or whether it can go “outside the fence” to regulate emissions.

Requiring a power plant to switch fuels might be permissible but not “forcing a coal plant to become a gas plant,” Leopold said. The decision raised questions about possible carbon capture rules and whether emissions reductions that are not cost-effective would be permitted, “for instance if a plant is scheduled to close in 5 years,” he said.

For the foreseeable future, the EPA is going to “hit singles and doubles rather than … swinging for the fence,” being careful to base its actions on statutory authority and not push its boundaries beyond what the courts deem permissible under West Virginia v. EPA, Leopold said.

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NARUC Panel Explores ‘Future Proofing’ EV Infrastructure

SAN DIEGO — Utility regulators are confronting myriad challenges in dealing with the growing need for electric vehicle chargers, including a quickening pace of obsolescence, a lack of uniform standards among charging stations, and lingering questions about who should deploy and pay for equipment.

And any meaningful response to those challenges will likely fall to the states, according to Phil Jones, executive director of the Alliance for Transportation Electrification (ATE) and a former member of the Washington Utilities and Transportation Commission.

“It appears to be a decision of the federal government not to do anything on climate and perhaps not even renew the EV tax credits,” Jones said during a July 18 panel on “future proofing” EV charging technology at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit. “The issues are going to be squarely in your laps in the states. That’s my prediction over the next three to four years, at least.” 

Following is some of what we heard during the panel.

Future Proofing Explained

Panel moderator Jamie Barber, director of the energy efficiency and renewable energy unit at the Georgia Public Service Commission, opened the discussion by pointing to a key problem utility commissions face in future proofing utility EV infrastructure investments.

“The regulatory process is often so long that by the time the commission approves a program or plan, the technology may already be out-of-date. So the question is, how should the commission plan for these short-lived assets?” Barber said.

“What does future proofing actually really mean?” said Marie Steele, vice president of electrification and energy services at NV Energy (NYSE:BRK.A). “When I think about it from a utility perspective, it’s very easy for us when we think about how to operate the greatest critical infrastructure that has reliability metrics around it. We focus on standardization; we focus on interoperability; we focus on reliability — also with that center of the customer experience. And grid integration is layered on top of it.”

NV Energy is allowed to own EV charging stations in Nevada, Steele noted, giving customers a choice of who can operate their sites: the utility, third-party providers or the customers themselves.

The utility previously took a “top-down” approach to encouraging development of charging sites by providing incentives. “‘Just do the best you can with moving the market’ was really how we designed our programs,” Steele said.

But with the approval last year of its $100 million Economic Recovery Transportation Electrification Plan, NV Energy is now taking a more “bottom-up” approach to developing charging sites, according to Steele. The plan is expected to produce 1,882 chargers at 120 sites across the state. (See NV Energy Gets Green Light for $100 MW EV Charger Plan.)

Under the new approach, NV Energy starts by developing site profiles with an eye to standardizing the charging network within utility’s entire service territory while determining cost estimates for each site “irrespective of ownership model.”

“So we want to have the standardization there and know what the project is going to cost,” Steele said. “And then when we get to interoperability, which is also still reliability and standardization, we have another long list of requirements for infrastructure that will be incentivized or owned by NV Energy.”

Those include minimum power levels, secure communications protocols and customer payment requirements.

“All of this so as to make sure that we can connect it into the grid, right? So that it benefits not just that individual EV driver or businesses that host EV charging stations. We can also optimize grid integration. That’s to the benefit of everybody,” she said.

‘Anchoring’ with Fleets

“We have a lot of clean energy assets, and one of the core principles we are trying to bring to this industry is the lessons learned from the solar and wind industry and apply those lessons to the scalability of [EV] infrastructure,” said Suresh Jayanthi, a senior director of sales and business development in the mobility solutions division at NextEra Energy Resources (NYSE:NEE).

For NextEra, that includes a technology-agnostic approach to the design and construction of EV charging sites and bringing finance and operations groups together to provide charging energy as a service to customers.

“This similar perspective for infrastructure will be critical as we look at all the variables that we just heard, figuring out the design [and] permit considerations, [and] bringing those into a platform that gives us predictable deliverables in terms of the time it takes to get through the interconnection and all the issues associated with that,” Jayanthi said.

Jayanthi, who currently focuses on developing charging solutions for medium- and heavy-duty vehicle fleets, said it’s important for the power industry to remember that fleet operators want to focus on what they do best, such as delivering packages on time.

“They’re not out to become infrastructure experts. They’re not trying to figure out how to build charging stations and figure out how to manage energy cases. We are trying to remove some of those bottlenecks, so as they look at electrification, their focus is on using the infrastructure as an enabler rather than a bottleneck. And that’s been our focus,” he said.

NextEra believes that its experience in developing fleet charging can provide lessons for a broader charging strategy.

“While consumer vehicle infrastructure is a critical enabler for the broad-based adoption of electric vehicles, fleets can provide a unique anchoring point around which we can look at infrastructure scaling, and it could have a multiplier effect,” Jayanthi said.

‘Right-sizing’ vs. Future Proofing

ATE’s Jones recounted a recent conversation with his daughter, who works as a legislative analyst in Washington’s capital, specializing in broadband policy.

“When I told my daughter I was going to be speaking about future proofing in San Diego … she says, ‘Dad, there’s no such thing as future proofing. How can you proof the future? There’s always going to be uncertainty,’” Jones said.

“I prefer the term ‘right-sizing for the future,’ or something like that. So what you’re trying to do is right-size the conduit, the pipes, the asphalt, concrete, transformers [and] switchgear,” he said. “You’re trying to get the right set of equipment in that first phase that can scale without the risk of stranded assets.”

Jones offered a list of recommendations for state regulators, including:

  • creating a transportation electrification (TE) plan;
  • finding a way to bring stakeholders (such as truckers) into the process so they can describe where their industries are going;
  • encouraging utilities to have a single point of contact on TE issues;
  • developing an interconnection review process for TE projects;
  • offering incentives and rebates, which should be revisited often;
  • encouraging utilities to frequently change their approved product lists to accommodate new companies coming into the EV space; and
  • looking around for best practices from across the country.

And with the longer curve of adoption for EVs, Jones also encouraged commissioners to consider allowing utilities to employ multiyear rate plans to recover costs from EV equipment.

“I know that consumer advocates and [the National Association of State Utility Consumer Advocates] and others may not be fans of this, but in order to bring the right-sizing of this technology and do least-cost planning for the long term, you may need to do that,” Jones said.

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SPP Board, Regulators to Consider Reserve Margin Increase

WESTMINSTER, Colo. — SPP and its members have agreed to boost the RTO’s planning reserve margin to 15% from 12% but remain at odds over the timing of the increase following Markets and Operations Policy Committee discussions that Chair Denise Buffington described as “contentious.”

SPP’s Regional State Committee and Board of Directors will each consider the issue during their virtual quarterly meetings, Monday and Tuesday, respectively.

SPP’s reserve margin requirement, currently 12%, is based on a probabilistic loss-of-load expectation (LOLE) study performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year). LREs unable to meet their obligation can incur financial penalties from the RTO.

“There was concern that moving too quickly will put members in non-compliance from the start,” Buffington told the Strategic Planning Committee the day after MOPC’s July 10-11 meeting. “There were also concerns the [generator interconnection] queue isn’t sufficiently caught up to actually get steel in the ground to meet those obligations.”

The grid operator’s staff wants to raise the planning reserve margin (PRM) to 15%, saying the 2021 study shows the current 12% requirement won’t satisfy the 1-in-10 metric for the 2023 summer season. They also said an increased margin of safety is necessary, as the 31 GW of nameplate wind capacity already present on the system has increased the risk of wind volatility, with more wind projects yet to come. A 15% PRM would incent new generation and reduce the risks and costs associated with extreme weather events, they said.

COO Lanny Nickell told MOPC that SPP doesn’t take lightly its responsibility to manage reliability across its footprint.

“We understand that some LREs expect to struggle to comply with the increased PRM requirement … We understand that taking actions to increase capacity necessary to comply will be costly, likely upwards of a billion dollars in capital investment,” he said.

“However, we also know that experiencing an unwanted interruption of power, especially during extreme heat or extreme cold conditions, is not only extremely frustrating to customers but also very costly, especially when loss of life is involved. A decision to increase the PRM requirement to 15% as soon as possible significantly reduces our risk that we experience another event where load is not able to be served,” Nickell said.

Stair-Step Approach

The Supply Adequacy Working Group (SAWG) is recommending a stair-step approach, with the PRM raised one percentage point over each of the next three years. It said that would give the GI queue time to reduce its backlog, adding certainty to generation forecasts, and allow LREs short of their capacity requirements to close their gaps.

SPP resisted. “As a reliability coordinator, we cannot endorse a 13% planning reserve margin next year when we think the right number is 15%,” Casey Cathey, director of system planning, said. “It’s just too much of a risk to endorse a stair-step approach, given the nature of our generation mix and the uncertainties around us.”

Staff updated MOPC on its efforts to clear the queue’s backlog, sticking to the 2024 completion target they set during April’s meeting. They said they’ve reduced the current queue’s number of active interconnection requests from 481, totaling 90.3 GW, to 466, totaling 87.27 GW as of June, thanks to the new three-phase interconnection study process. (See FERC OKs New SPP Interconnection Process.)

SPP has added more than 25 GW of generation the last five years, most of it from renewable resources.

Usha Turner 2022-07-11 (RTO Insider LLC) FI.jpgUsha Turner, OG&E | © RTO Insider LLC

“We should make certain [our current processes] are reflective of the current changes in our industry,” Oklahoma Gas & Electric’s Usha Turner said. “As we’re looking at 15%, given what we are seeing in the queue and the nature of what’s in the queue, is that enough?

“We’re evolving as we’re seeing things happening,” she said. “We need to better reflect the nature of our generation.”

Stakeholders in various working groups have pointed out the LOLE study does not include 2011 and 2021 weather-related impacts, future forced outage rates, the limited availability of demand response or any safety margin beyond the 1-in-10 reliability metric.

They said a larger, immediate increase in the PRM adds to market uncertainty and could leave LREs unable to cure capacity shortfalls. They also said they are concerned that even if excess capacity exists, it might not be available for purchase.

Nickell said that were the 15% PRM required by 2023, up to a dozen LREs would not be able to meet their obligations. Cathey noted SPP has about 3.6 GW of capacity available for purchase, but Turner responded that in her experience, that capacity is not available.

Midwest Energy’s Bill Dowling, among those favoring the SAWG approach, said instituting the 15% PRM immediately would prevent generators from rethinking retirement plans “that were devised with at least an assumption that the planning reserve margin wasn’t going to make a big jump.

“I don’t think we can expect to get out of this by saying we need 15%,” Dowling said. “We need time.”

Natasha Henderson 2022-07-11 (RTO Insider LLC) FI.jpgSAWG chair Natasha Henderson explains stakeholders’ position during PRM discussion. | © RTO Insider LLC

SAWG chair Natasha Henderson of Golden Spread Electric Cooperative, suggested it would be helpful to gather additional metrics around energy uncertainty. “What do we have now? What did we have a few years ago? What will we have going forward?”

Her recommendation gained support from Nickell.

After rejecting a suggestion to delay the PRM’s consideration until the October MOPC meeting, members voted on several motions before arriving at a consensus. A suggestion to increase the PRM to 13% in 2023 and 15% in 2025 fell short of two-thirds approval at 60%. Endorsing the SAWG’s stair-step increase but incorporating a waiver process should the RSC reject the working group’s recommendation won only 48% approval.

However, a straight motion on the stair-step method passed with 95% approval. Members followed that by endorsing the SAWG’s recommendation for a performance-based accreditation for conventional resources (thermal and hydro), with a one-year delay in the implementation date.

The performance-based accreditation differentiates resources according to their historical reliability but does not change the total capacity required to meet system reliability. It would be the first time SPP has applied this methodology.

MOPC then approved a motion directing staff to create a process for approving waivers from the resource adequacy requirement should LREs not have sufficient time to resolve their deficiency.

As the dust settled, Buffington quipped that MOPC could soon expect a quiz on Robert’s Rules of Order. She was greeted with laughter.

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NextEra Continues to Shine Brightly

NextEra Energy (NYSE:NEE) leadership said Friday that “powerful tailwinds” continue to support strong demand for renewables, repeating a message from last month’s investor conference.

“High power prices and high gas prices … are helping to make renewables the most economic form of generation,” CFO Kirk Crews said during the company’s quarterly conference call with financial analysts.

Crews said NextEra’s renewable developer, NextEra Energy Resources, added slightly more than 2 GW to a backlog that now totals more than 19.6 GW. That included about 1.2 GW of solar projects, the second largest quarter of solar origination in our history.

The Juno Beach, Fla.-based company said it was pleased with the government’s recent decision to waive additional duties for two years on solar panels imported from Malaysia, Thailand, Cambodia and Vietnam. The U.S. Department of Commerce has opened an investigation into claims that panels imported from those countries contain Chinese components subject to tariffs imposed by the Trump administration and continued under President Biden. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)

Crews said NextEra expects its suppliers will be making ingots and wafers outside of China at the end of those two years. The Commerce Department staff have “publicly stated that panels with wafers made outside of China are not subject to its investigation,” he said.

NextEra reported earnings of $1.38 billion ($0.70/share), compared to last year’s second quarter of $256 million ($0.13/share). Earnings adjusted for one-time gains and costs came in at $1.59 billion ($0.81/share), exceeding Zacks Investment Research’s consensus of 75 cents/share.

During the quarter, NextEra commissioned the 1.2-GW natural gas-fired Dania Beach Clean Energy Center and placed into service the 176-mile North Florida Resiliency Connection transmission line. The line physically connects NextEra’s Florida Power & Light and Gulf Power grids and is projected to yield $1.5 billion in system benefits through consolidated operations.

“Smart capital investments such as these help lower costs and improve reliability for customers, NextEra CEO John Ketchum said.

The company’s share price gained $1.55 on Friday and closed at $80.25.

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Maine Environmental Board Denies Appeals of NECEC Transmission Line Permit

The Maine Board of Environmental Protection last week removed one potential obstacle to the 145-mile New England Clean Energy Connect (NECEC) transmission line, upholding Central Maine Power’s construction permit.

After two days of oral arguments, the board voted Thursday to deny appeals by the Natural Resources Council of Maine (NRCM), NextEra Energy and a group of local entities and individuals to vacate a 2020 Department of Environmental Protection (DEP) order approving CMP’s project application.

The board confirmed DEP’s order approving a permit to construct the project and modified parts of the order related to decommissioning and habitat impact compensation. In addition, the board denied appellants’ request for a new public hearing on CMP’s application.

CMP cannot resume construction, however, unless it prevails in its court challenge of a November 2021 referendum blocking the project.

Compensation, Decommissioning

Prior to hearing oral arguments on the appeals, the board issued a proposed order finding that the department’s order for CMP to conserve 40,000 acres to compensate for the effects of the project on wildlife habitat was sufficient. After hearing petitioners’ arguments, however, the board increased the total compensation to 50,000 acres.

NRMC claimed that the standard compensation ratio used by DEP to calculate the total acreage to be conserved does not reflect the importance of the affected lands. Maine law relies on an 8:1 ratio to replace any lost function from activities that alter wetlands, and DEP applied that standard in the order using an estimated 5,000 acres of baseline affected lands.

“The 8:1 ratio is a typical ratio, but the problem is this is not a typical area — it is a very special part of the state,” said attorney James Kilbreth, representative for NRCM, in testimony Wednesday. “The impacts here are more consequential than in other parts of the state, and the compensation should reflect that higher degree of value.”

In its 2020 appeal of the department’s order approving the project permit, NRCM said that the project is sited in a part of Maine that “supports exception biodiversity,” making the area a “unique and important wildlife habitat.”

The board agreed that the compensation ratio should be higher, and increased it to 10:1, resulting in the new 50,000-acre conservation area.

To address concerns about decommissioning guidelines for the project, the board’s proposed order upheld parts of DEP’s original decommissioning plan, while also addressing what might happen if project construction is completed and not energized or not completed.

Permit Suspended

CMP began construction on the project in January 2021 and halted construction in November when DEP Commissioner Melanie Loyzim issued a suspension order for CMP’s permit to construct. (See NECEC Halts Tx Line Construction, Regulators Suspend Env. Permit.) At that time, CMP had already completed clearing activities on four of the five line segments and begun other infrastructure work.

The board’s proposed order called for CMP to submit a decommissioning plan to DEP for review prior to resuming construction and to begin decommissioning within 18 months of nonrenewal or termination of current power contracts. After hearing oral arguments, the board added a condition to its final order for decommissioning to begin in August 2024 if construction has not resumed by that time.

That 24-month period will allow for an appeal of the board’s decision to play out, if one is filed, board staff said Thursday.

Suspension of CMP’s permit to construct will remain in place unless the Maine Supreme Court decides in favor of CMP in NECEC Transmission LLC, et al. v. Bureau of Parks and Lands, which challenges the legal authority of a referendum on transmission development passed by Maine voters in November. The court heard oral arguments in that case in May.

The referendum authorizes a statutory change requiring legislators to approve high-voltage transmission lines greater than 50 miles that are not necessary for reliability purposes. CMP is asking the court to block retroactive application of that law.

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Westerners Get Tips on Being ‘Little Bitty Cog’ in an RTO World

SAN DIEGO — Officials in Western states looking to join an RTO should know a key thing about organized markets, according to those familiar with them: They will require a lot of time and resources from your regulators and consumer advocates.

“There are times when I think I’m a little bitty cog in a big RTO world, and that the RTO is my full-time job and the other state regulatory stuff is what I end up with when I’m not busy with RTO stuff,” Arkansas Public Service Commission Chair Ted Thomas said Tuesday at the National Association of Regulatory Utility Commissioners (NARUC) Summer Policy Summit.

Thomas was speaking on a panel to provide Western regulators and advocates with insights on how to position themselves to participate in any organized electricity markets that take root in the region.

As a regulator experienced with both SPP and MISO, Thomas said he’s confident in his agency’s ability to help shape market policy.

“What I worry about is someone who’s newer, that doesn’t have the background, and then they show up and they can get [run] over by a big snowball — not even realizing what hit them, and there’s nobody there to help them help themselves,” he said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, advised Westerners of the benefits of state consumer advocates and utility commissions being aligned on their positions on RTO affairs.

“For me that’s very helpful because I do talk to state commissions, their advisers or staff a lot, and it’s a great working relationship. I’m able to provide some of their opinions in the stakeholder process along with ours, and they have a lot more influence than we do,” Poulos said.

Poulos said RTO/ISO market monitors can be a valuable source of information because electricity customers and their advocates usually have less information than other stakeholders because they don’t directly participate in or regulate the markets.

Although PJM’s territory includes 65 million residential customers, those ratepayers represent just 1.4% of the votes “at the lower levels” of the RTO’s consensus-based stakeholder process, and have little visibility into the transmission planning process, Poulos said.

“There’s public power, there’s industrial customers, but for us as customers — those who pay the bills — we have very little influence,” he said.

Amanda Bradshaw, energy markets adviser with FERC’s Office of Public Participation (OPP), said there are many groups “that are recognizing that RTOs have an increasing impact on everyday people [and] on broader energy policy questions that people care about.

“But they might not necessarily understand or have full information about FERC processes, or about the market underpinnings of those policy goals that they care about,” she said.

Established in 2021, the OPP “is trying to understand how we can reach out to the public and bridge a lot of information gaps,” Bradshaw said. The office also seeks to increase understanding of RTO processes and help public interest groups figure out how get involved in those processes from the beginning.

“How do you actually participate in those processes if you don’t understand how those things work? How do you allocate staff resources to attend those meetings, especially when it’s necessary sometimes to attend in person?” she asked.

“Typical citizens don’t have expertise; they have passion,” Thomas said. “They might have environmental passion. … They might just want the lights to come on [and say], ‘Leave me alone.’ But for that person to have input … you need expertise. But having expertise doesn’t do any good if you don’t have access to the information, and to me, that’s a big part of that problem.”

‘Complex Subject Matter

Panel moderator Kent Chandler, chair of the Kentucky Public Service Commission, asked panelists whether they have enough resources to have a “meaningful impact” on RTO processes. Each answered with a resounding “no.” He followed up with a question about what barriers must be removed to encourage participation by those outside the industry.

“I think you start with inclusiveness: barriers to entry around cost, membership fees, differing eligibility requirements for membership in the RTOs,” said John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project.

Moore said his organization recently joined SPP for the $6,000 membership fee after FERC eliminated the RTO’s $50,000 deposit fee and $100,000 exit fee for all members. In PJM, he noted, the Sustainable FERC Project cannot become a full member and — along with the states — is barred from attending Liaison Committee meetings with  the Board of Managers. Moore also pointed to the restrictions the press faces in covering NEPOOL, something that “FERC said is okay, more or less.” NEPOOL meetings are closed to the public; although RTO Insider’s ISO-NE correspondent attends meetings as an end-use customer, NEPOOL rules bar quoting from members’ discussions. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

“Another set of huge issues is around data access and overall understandability of the issues,” he said. “There’s a lot of chicken-and-egg issues going on here. The reason a lot of non-traditional groups and entities don’t show up at the RTOs is that it’s just very complex subject matter.”

Moore said working groups at WECC and other organizations in the West make the region’s electricity data more accessible. “My experience has been lots of times — and somebody in the West can correct me — it’s actually easier to get a lot of the data we need to input in our models than it’s been in the East; and a lot of different standards are applied in different RTOs.”

FERC’s Bradshaw said groups lacking expertise in energy regulation tell the OPP, “‘We’re just having a really difficult time crafting these proceedings that we need to be involved in, and that would be relevant to us,’” Bradshaw said. “I think it’s even difficult when you do have those resources, when you’re able to hire an attorney or contract a law firm to track those things for you.”

“The real resource issue for the states is state staff and state time.” Thomas said.

Balancing Act

Thomas believes the U.S. grid has become more robust since the catastrophic blackout that brought down the Northeast grid in 2003, in part because of new investments and the “balance” that comes with having states certify utility transmission plans after being included in the negotiation process.

“I think one of the most important things that comes out of this is that balance — the balance of states and your roles as commissioners and your ability to maintain that balance,” Poulos said.

But Poulos sees a lack of balance in PJM’s current transmission process. While he lauded the RTO for fostering wholesale competition in power generation, he criticized it for a corresponding lack of competition and transparency in transmission planning.

“We don’t really know what PJM’s role as a planner is in a lot of cases because since 2012, or [FERC] Order 1000, there’s been a lot of push towards competition, but what happened is a transmission owners said we’re gonna push everything away from those types of projects,” he said.

As a result, Poulos said, the majority of the RTO’s transmission projects are “supplemental” ones that waive competition.

Poulos thinks there’s an open question about the roles of PJM, the transmission owners and the states in the “vast majority” of the RTO’s transmission planning.

“One of the deepest frustrations we have is that lack of ability to be involved in that process,” he said.

Moore said there’s now an “implicit connection” between transmission planning and resource adequacy.

“And I think this is something that states and FERC are grappling with, obviously through the [transmission Notice of Proposed Rulemaking] and through the dialogue that has happened with FERC and the state commissions, and the increasing realization with our transforming grid mix that there are going to be more out-of-state resources that have to be relied on to help meet reliability and state resource adequacy needs,” Moore said. (See States Back Interregional Transfer Requirement.)

Poulos wrapped up his comments by advising Western state officials on what they should consider as they contemplate joining an RTO.

“I would say the one thing is, if anything goes wrong in the system in your state, as a commissioner you are the ones who are going to be accountable, so you need to have that ability to have a say in what goes on,” he said.

State officials also need to immediately establish transparency in the RTO and guarantee their representation, preferably with a reserved seat on the board of directors, he said.

Moore said states need to ensure that RTOs make efforts to include different groups in their processes.

“And even if they’re not full-time stakeholders, these groups and communities need to understand what the RTO is doing is actually affecting them, so they can in some way start to influence that process. So don’t forget about equity in this process,” he said.

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Consumer Groups File FERC Complaint Against MISO

An alliance of consumer groups on Friday jointly filed a complaint with FERC against MISO’s practice of respecting state rights-of-first-refusal (ROFR) laws in its regional transmission planning.

The consumer alliance asked the commission to block MISO and other RTOs from applying “anticompetitive” ROFR laws to their regional transmission planning and cost-allocation processes.

The group made the filing as the RTO’s Board of Directors prepares to consider Monday the $10.4-billion, 18-project long-range transmission plan (LRTP) for its Midwestern states. The portfolio is the first of four that MISO is planning to modernize its system.

The group said ROFR laws conflict with FERC’s rules on transmission competition and the commission’s obligation to establish just and reasonable rates.

The alliance includes the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers, the Wisconsin Industrial Energy Group, Resale Power Group of Iowa, Association of Businesses Advocating Tariff Equity and the Michigan Chemistry Council.

The groups said MISO should not hamstring itself by maintaining tariff provisions that prohibit it from holding a competitive solicitation for regionally cost-allocated projects. It said ROFR laws in that application are unjust and unreasonable.

FERC should prohibit the grid operator from recognizing the laws in the LRTP and order the RTO to hold competitive solicitations for projects located in those states, the consumer alliance said.

MISO estimates $1 billion of the portfolio will ultimately be open to competition. The grid operator said nearly $4 billion worth of the projects are considered upgrades to existing facilities, while another $5.5 billion of projects are in states that have enacted ROFR legislation.

Michigan, Minnesota, Iowa and the Dakotas all have ROFR laws; Wisconsin lawmakers have considered one but haven’t passed it. Additionally, MISO is likely to scrap its only market efficiency project assigned to MISO South after Texas’s ROFR legislation delayed the project’s start by years. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

The RTO is planning to prepare requests for proposals where ROFR laws don’t prohibit competitive bidding. In those states without the legislation, incumbent transmission developers will need to provide to their regulators a notice of intent to construct.

The consumer alliance insisted that its complaint wasn’t seeking to slow down any reliability projects, but that MISO “delay issuing any notices to construct to projects currently protected by state ROFR laws” in the LRTP’s first cycle.

“Circumstances have substantially changed since 2013-2014 when the commission accepted the MISO tariff provisions … that mandate that MISO apply any state law that includes a ROFR to circumvent transmission competition in MISO,” the alliance said.

The alliance argued it’s now clear that ROFRs are being enacted to circumvent FERC’s competition mandate and “that the burdens of state ROFR requirements do not fall solely on customers within ROFR states, forcing pro-competition states to pay for the parochial policies of incumbent preference states.” They said ROFR laws are premised on the fear that incumbents will be outbid by competitive developers, are “economically inefficient by design” and “needlessly raise costs to consumers.”

“The costs at issue are far from modest, and so the time is ripe for the commission to act,” the alliance argued.

Industrial Energy Consumers of America President Paul Cicio said should $5.5 billion of transmission projects be automatically assigned to incumbent utilities, consumers in MISO Midwest will pay more for regional transmission than if they were bid out.

“We are requesting that the commission act quickly to find MISO’s provisions to be unjust and unreasonable and to require the replacement rate to be based on project costs resulting from competitive solicitation,” Cicio said in a statement.