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October 31, 2024

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Canadian Wildfires Trigger ISO-NE Capacity Deficiency

Forest fires in Québec forced the shutdown of a Hydro-Québec transmission line during New England’s peak-demand evening hours Wednesday, leading to a capacity deficiency and requiring ISO-NE to take emergency actions to balance the grid.

The event marks just the third capacity deficiency event in New England since 2016; the most recent prior incident was on Dec. 24, 2022. ISO-NE was able to draw on operating reserves to avoid major issues.

“The transmission outage occurring in the midst of the evening peak meant that sufficient resources were not able to respond quickly enough to avoid the capacity deficiency,” ISO-NE wrote in a press release, noting that the transmission issue coincided with higher-than-expected peak evening demand.

While calling on the region’s reserve resources, ISO-NE declared an Energy Emergency Alert Level 1, the lowest of the RTO’s three alert levels. These actions helped mitigate the capacity deficiency within a half-hour, and ISO-NE did not ask the public to reduce its energy consumption.

“In and of themselves, capacity deficiencies are not always emergencies,” ISO-NE said. “They simply mean that ISO operators are taking additional actions to maintain system reliability.”

A Hydro-Québec spokesperson told RTO Insider in a statement that the transmission outage was the result of forest fires in the Baie-James region of Québec, which caused a temporary shutdown of the company’s Phase-2 line.

“Heat and smoke can trigger automated system protection mechanisms, which will essentially shut down the power line in order to protect it,” Hydro-Québec said. “Our bulk transmission infrastructure has not suffered any damage as a result of the forest fires. We remain in constant communication with our ISO partners, providing as much visibility as we can on the current fire situation.”

The company also highlighted the link between the accelerating consequences of manmade climate change and the massive early season wildfires in Québec.

“While forest fires are not a new phenomenon, the intensity and increased frequency of these events in North America are the result of climate change,” Hydro-Québec said. “The amplitude of this event should serve as a clear reminder that we need to accelerate every effort towards transitioning away from the burning of fossils fuels for electricity generation.”

The wildfires already have broken Canada’s record for most area burned in a single year, and government officials expect above-average fire conditions to continue through July and August in many regions of the country.

Kristina Dahl, principal climate scientist for the Climate & Energy program at the Union of Concerned Scientists, said that while a large range of factors have contributed to the massive Canadian wildfires, climate change is a major driver.

“There’s a very clear connection between climate change and worsening wildfires,” Dahl said. She noted that climate change exacerbates wildfire risks by increasing temperatures and drying out ecosystems, as well as enabling tree-killing insects to survive the winter, which creates additional fuel for wildfires.

“It’s really alarming what’s happened in Canada so far this wildfire season,” Dahl added. “Wildfires have burned over 20 million acres of land; that’s roughly an area the size of the state of Maine.”

In early June, ISO-NE reported that wildfire smoke had led to reduced solar generation across the region. It emphasized the difficulty in forecasting demand amid the effects of this smoke because of the lack of historical data. (See RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes.)

ISO-NE also recently released the preliminary results of its joint study with the Electric Power Research Institute about the grid reliability impacts of extreme weather, looking at the summer of 2027. While the study found no energy shortfall risk, it did not analyze the risks posed by wildfires to the grid.

“We did not directly consider wildfire risks, as the assessment was focused on resource adequacy risks where wildfires would not be expected to impact enough supply resources simultaneously in the region to be a primary hazard to consider for resource adequacy risk,” Daniel Brooks, EPRI vice president of integrated grid and energy systems, said in a statement to RTO Insider. “Wildfire risks might be a contributing factor potentially during extreme heat scenarios in the future. One area we could add for future versions would be the import capability with wildfire impacting transmission from neighboring regions such as Québec.”

Susan Muller, senior energy analyst for UCS, said the reliability issues experienced last week highlight the need to rapidly transition away from fossil fuels and to recognize the reliability attributes of nonemitting resources.

For clean energy sources, “you’re getting power, but you are also reducing the likelihood of extreme weather because you’re no longer adding carbon to the atmosphere,” Muller said.

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CARB, Manufacturers Partner to Support Clean Truck Rules

As a court battle heats up over California’s zero-emission truck regulations, a group of truck manufacturers on Thursday committed to follow the ZEV rules even if they’re overturned.

The commitment came through the Clean Truck Partnership, an agreement between leading truck manufacturers and the California Air Resources Board (CARB).

In exchange for their pledge to transition to zero-emission vehicles and meet tailpipe emission standards, CARB agreed to give manufacturers more compliance flexibility. The agency also promised to provide a minimum of four years’ lead time before imposing new requirements and at least three years of regulatory stability.

CARB Chair Liane Randolph called the agreement an “unprecedented collaboration.”

“This agreement makes it clear that we have shared goals to tackle pollution and climate change and to ensure the success of the truck owners and operators who provide critical services to California’s economy,” Randolph said in a statement.

The Clean Truck Partnership includes CARB and the Truck and Engine Manufacturers Association (EMA), along with the following manufacturers:

    • Cummins Inc.
    • Daimler Truck North America
    • Ford Motor Co.
    • General Motors Co.
    • Hino Motors Limited Inc.
    • Isuzu Technical Center of America Inc.
    • Navistar Inc.
    • Stellantis N.V.
    • Volvo Group North America

ACT Targeted

The federal Clean Air Act allows California to request an EPA waiver to enforce its own emission standards for new motor vehicles. EPA granted a waiver for CARB’s Advanced Clean Trucks regulation in March. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)

The regulation, which CARB adopted in 2020, requires truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035. In addition, CARB adopted in April the Advanced Clean Fleets regulation, which will ban the sale of diesel trucks in the state starting in 2036. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.)

Other states may adopt California’s regulations rather than use federal standards. States that have adopted California’s ACT regulation include Colorado, Massachusetts, New Jersey, New York, Oregon, Vermont and Washington.

Under the Clean Truck Partnership agreement, truck manufacturers committed to selling as many zero-emission trucks as reasonably possible in every state that has adopted ACT. Those efforts will be “irrespective of the outcome of any litigation that has been filed or may be filed challenging the waivers or authorizations for those regulations or CARB’s or any state’s overall authority to implement those regulations.”

The EMA and the truck makers also agreed to be neutral when states are considering the adoption of ACT. But the parties can still comment on implementation issues, according to terms of the agreement.

On CARB’s end of the agreement, agency staff will propose giving manufacturers three years, rather than one year, to make up deficits in meeting ZEV requirements. CARB also committed to holding a workshop this year to discuss the concept of pooling ZEV credits and deficits across ACT states.

Also this year, CARB will hold a workshop “to discuss the appropriate role of hydrogen-fueled internal combustion engines” in meeting ZEV requirements.

In addition to ACT, the agreement addresses CARB’s so-called omnibus rules, which regulate truck tailpipe emissions. CARB has agreed to align its rules with EPA’s 2027 regulations for nitrogen oxide emissions and modify some parts of its 2024 NOx emission regulations.

“This alignment between California and the Environmental Protection Agency’s national standards for model year 2027 and beyond will help us get more clean trucks on the road across the country,” Cynthia Williams, global director of sustainability, homologation and compliance at Ford Motor Co., said in a statement.

Court Battle Waged

Last month, a coalition of 19 states, led by Iowa Attorney General Brenna Bird, petitioned a federal appellate court to review EPA’s approval of CARB’s Advanced Clean Trucks regulation.

Groups including the Western States Trucking Association and the Construction Industry Air Quality Coalition filed similar petitions.

Bird said in a release that ACT forces truckers to buy electric vehicles and “regulates trucking out of existence” through zero-emission standards.

Last week, California officials announced they were leading their own multi-state coalition seeking to intervene in the ACT lawsuits. Joining California in the motion to intervene were Colorado, Connecticut, Delaware, Hawaii, Illinois, Maine, Maryland, Massachusetts, Minnesota, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont and Washington, the District of Columbia, and the cities of Los Angeles and New York.

The Environmental Defense Fund and three other environmental organizations also filed a motion to intervene last week.

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California Invests in Zero-emission Port Equipment

California Gov. Gavin Newsom announced $1.5 billion in port infrastructure upgrades Thursday, including $450 million to fund zero-emission locomotives, vessels and vehicles at some of the West Coast’s largest shipping container ports.

“No other state has a supply chain as critical to the national and global economy as California,” Newsom said in a statement. “These investments — unprecedented in scope and scale — will modernize our ports, reduce pollution, eliminate bottlenecks and create a more dynamic distribution network.”

The money will finance 28 projects that together will create an estimated 20,000 jobs, the statement said.

“The historic level of state funding also puts these projects in a stronger position to compete for significant federal infrastructure dollars from the Biden-Harris administration,” California Transportation Secretary Toks Omishakin said during an event announcing the awards Thursday at the Port of Long Beach.

The ports of Long Beach and Los Angeles — among the three busiest container shipping ports in the U.S., according to maritime information website Marine Insight — are trying to convert to zero-emission operations in coming years.

As part of the grants, the Port of Long Beach was awarded more than $383 million to help modernize its freight transport system at the port and in surrounding communities, the California State Transportation Agency said in its summary of the projects.

The funding will pay for the development of a battery plug-in tugboat and up to 12 long-haul and switching zero-emission locomotives. It also will finance nine hydrogen fuel cell “top handlers” to stack and move freight containers and 44 pieces of zero-emission equipment to replace diesel tractors, forklifts and other heavy equipment, the agency said.

A $46 million grant to the Port of Stockton will fund a zero-emission electric railcar mover. And more than $15 million will help expand Sierra Northern Railway’s efforts to develop and demonstrate hydrogen-powered switching locomotives to serve the Port of West Sacramento.

The Port of Oakland, the largest container port in Northern California, will receive more than $103 million for its modernization efforts. The money will help pay for battery-electric tractor rigs and charging stations, hydrogen fuel cell top handlers and a battery storage system.

“We look forward to our continued partnership with Secretary Omishakin in building an Oakland seaport for the next generation that uses clean, zero-emissions energy like electricity and hydrogen,” Port of Oakland Executive Director Danny Wan said in a statement.

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GOP Senators Call for FERC Conferences on EPA Power Plant Rule

Two key Republican senators want FERC to play a more active, public role in evaluating the potential impacts of the power plant emissions rules EPA proposed in May. (See EPA Proposes New Emissions Standards for Power Plants.)

Energy and Natural Resources (ENR) Committee Ranking Member Sen. John Barrasso (R-Wyo.) and Environment and Public Works Committee Ranking Member Sen. Shelley Moore Capito (R-W.Va.) sent a letter to the commission Wednesday urging it to hold a series of technical conferences on the rule.

“The proposal presents unjustifiable claims about the future availability of technologies — including carbon capture, clean hydrogen and the related infrastructure — used to power our electric grids,” Barrasso and Capito wrote in the letter. “In light of recent testimony before Congress and the projected impact of the Proposed Clean Power Plan 2.0, we ask you to convene as soon as possible a series of technical conferences to assess the potential impact of the proposed rule on electric reliability.”

The Federal Power Act requires FERC to protect electric reliability through mandatory standards and Congress more generally looks to the commission to safeguard the quality of interstate electric and natural gas service, the two wrote.

The ENR Committee recently held a pair of hearings on FERC oversight and reliability. During one of them, the commission’s two Republicans warned of a pending reliability crisis. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.) Commissioner James Danly warned of “an impending, but avoidable, reliability crisis,” and Commissioner Mark Christie said the crisis would occur if the rapid subtraction of dispatchable resources continued unabated.

Chairman Willie Phillips told the committee he was concerned about the pace of power plant retirements and said the commission needed to keep an eye on it. Similar concerns were echoed by the heads of NERC and PJM at a later hearing. (See Robb Warns of ‘Serious Disruptions’ from Grid Transition.)

“These witnesses expressed the critical, consistent concern that the premature retirement of dispatchable generation is frequently driven by government actions, including rulemakings from the EPA,” the letter said. “The Proposed Clean Power Plan 2.0 appears to pose a significant threat to the remaining dispatchable fleet when the nation can afford it least.”

Back when the original Clean Power Plan was finalized in 2015, President Obama’s EPA worked with FERC and the commission held a series of technical conferences on the plan’s potential impact on reliability, which all included testimony from EPA leadership, the letter said.

The letter said that without a similar effort from FERC to a build a record, the commission’s consultations with EPA on the rule “are likely to be ineffective.”

“EPA clearly lacks the expertise to project accurately the impact of its rulemaking on electric reliability without deeply informed and engaged participation from FERC and those subject to its jurisdiction that are charged with the obligation to generate and deliver electricity in order to meet continuous demand for electric service,” Barrasso and Capito wrote.

Behind the Scenes

While the letter argues for more public coordination between the two agencies, former FERC Chair Richard Glick said in an interview that the two closely coordinated on areas that implicated each other’s jurisdictions.

“Behind the scenes, FERC and EPA have conversations often,” Glick said. “FERC often provides technical assistance to agencies like the EPA, for instance, if there’s a concern about a particular upcoming rulemaking that EPA is looking at and what that impact might be on the reliability of the grid.”

Those kinds of conversations happened when Glick was at the agency, and he expects they have continued, though he acknowledged not having inside information about what has occurred since he left. It is ultimately up to Phillips whether he wants to go the more formal route of technical conferences as requested by the two senators, Glick said.

Any information shared between the agencies behind the scenes is going to be part of the public record anyway, Glick said.

The senators’ letter also complained about EPA’s decision to grant a brief extension for its comment deadline to Aug. 8, when many parties, including key trade associations and the ISO/RTO Council, had asked for an extension into the fall.

An EPA spokesman said the agency would respond to all comments in its final rule when it is issued. In the proposed rule itself, the EPA said it would coordinate with FERC and mentioned it signed a memorandum with the Department of Energy this spring that included consultation with the commission, NERC and state regulators. (See: DOE, EPA Team Up on Reliability Efforts.)

Electric Power Supply Association CEO Todd Snitchler said in a statement that trade group would support public coordination between FERC and EPA on the rule’s potential impacts, of which the group has been critical since it was released.

“While we support and our members actively contribute to the expansion of cost-effective clean energy, EPSA remains deeply concerned about the potential impact of the EPA’s proposed rules on critical natural gas power plants needed to provide reliable electric supply,” Snitchler said.

No existing commercial power plants in the country are using carbon capture and sequestration and no current technologies can meet 24/7 demand that can be “deployed quickly, cost effectively and at scale to fill the gap left by existing resources likely to be put out of business by the EPA’s aggressive new restrictions,” he added.

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FERC Accepts NERC Budget Update

FERC on Monday completed a back-and-forth on NERC’s 2023 Business Plan and Budget that it began last November with an order accepting the ERO’s clarification of the commission’s questions (RR22-4-002).

The commission said it was satisfied with NERC’s compliance filing, which the ERO submitted in January in response to FERC’s order accepting the budget in November. (See FERC Orders Clarification in ERO Budget Filing.) FERC also accepted the 2023 business plans and budgets of the regional entities and the Western Interconnection Regional Advisory Board in the same filing.

FERC had ordered the compliance filing to clear up a number of questions, some initially raised by the Edison Electric Institute, about how the funds in the budget were to be used. The commission said its oversight duties would be best served by “additional transparency” into costs relating to the Electricity Information Sharing and Analysis Center’s (E-ISAC) operations — particularly how NERC’s new Business Technology Department relates to the E-ISAC — in addition to the program’s relationship with outside partners and vendors.

The commission also demanded information on NERC’s fixed asset costs and allocation of its loan proceeds, and the inclusion of natural gas companies in the E-ISAC and the Cybersecurity Risk Information Sharing Program (CRISP).

In its filing, NERC explained that the Business Technology Department supports all of the ERO, including the E-ISAC. The organization told the commission that in its budget, costs directly assigned to a particular department may be reflected as indirect costs in each department that it supports; for example, the 2023 E-ISAC budget includes fixed asset additions of $1.1 million, $258,000 of which are directly assigned to the E-ISAC and $928,000 of which are allocated as indirect expenses from the administrative departments.

Explaining the $4 million loan proceeds, which the budget said would be used for software investments, NERC said the funds were specifically for the Align and Secure Evidence Locker projects. The ERO said budgeting this financing activity in its General and Administrative line item was “consistent with NERC’s historical practice” regarding software financing but acknowledged the commission’s “concern” about the lack of clarity this creates regarding where funds finally are to be spent.

NERC said future budgets would “allocate the budgeted capital financing activity … using weighted percentages of departments’ capital software spending.”

Regarding the E-ISAC vendor affiliate program, NERC said the program’s tiered structure — under which vendors may pay more for additional benefits such as access to networking sessions at the GridSecCon security conference — allows vendors of smaller sizes and resources to access the program that otherwise might not be able to join. The ERO also outlined its screening process for the program and asserted that the E-ISAC reviews the materials of vendors who will participate in its events to ensure they do not contain sales or promotional content, another concern raised by FERC.

Finally, NERC explained that the E-ISAC’s collaboration with the Downstream Natural Gas Information Sharing and Analysis Center provides the E-ISAC’s members with “increased insights into threats affecting a sector that has many overlaps” with their business through the sharing of informational bulletins. The ERO also said natural gas utilities that participate in CRISP pay for their access the same as any other participants.

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Calif. Legislature Approves Key Infrastructure Bills

California lawmakers on Wednesday approved the central components of Gov. Gavin Newsom’s package of infrastructure bills to speed clean energy development, sending the measures to Newsom for his signature.

The state Senate gave final approval to Senate Bill 149, which would streamline judicial review of clean energy and transportation projects by requiring that challenges to the projects under the California Environmental Quality Act (CEQA) be resolved by the courts within 270 days, including appeals. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)

The Senate also approved SB 147, which would allow the incidental taking of species that are fully protected under the state Endangered Species Act during the construction of infrastructure projects. It would also declassify the peregrine falcon, brown pelican and thicktail chub, a small fish, from the law’s list of fully protected species.

Another bill passed by the Senate on Wednesday, Assembly Bill 124, would authorize the California Infrastructure and Economic Development Bank and the state Department of Water Resources to use funding from the federal Inflation Reduction Act to finance projects that reduce greenhouse gas emissions.

“California is one step closer to building the projects that will power our homes with clean energy, ensure safe drinking water, and modernize our transportation system,” Newsom said in a statement after the bills passed .

Despite objections from environmental groups and some fellow Democrats, Newsom made it a priority to remove obstacles that could stop or delay construction of needed infrastructure. The state must add thousands of megawatts of new generation and storage resources in the next 10 years to meet its 100% clean energy goal by 2045 while maintaining reliability.

“I look forward to signing these bills to build California’s clean future, faster,” Newsom said in his statement. “Thanks to our partners in the Legislature, we’re about to embark on a clean construction boom that maximizes the unprecedented funding available from the Biden-Harris administration.”

Another measure in the package, AB 122, cleared the Senate and state Assembly on June 27. It would allow but mitigate the removal of western Joshua trees, which the state Fish and Game Commission is considering listing under the California Endangered Species Act. The iconic California desert plants occupy large swaths of land slated for utility-scale solar arrays and battery storage. Newsom has yet to sign the measure.

At least one other bill still requires Senate approval. AB 126 would extend funding for the state’s Clean Transportation Program and the Air Quality Management Program through Department of Motor Vehicle fees and require an annual funding allocation of 10% for hydrogen refueling stations from the Clean Transportation Program through 2030 or until a sufficient network of refueling stations exist.

Newsom and legislative leaders announced their agreement on the infrastructure bills June 26 as part of a larger deal on the fiscal year 2023/24 state budget. (See Calif. Governor, Lawmakers Agree on Infrastructure Bills.)

The bills will take effect immediately upon Newsom’s signature.

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FERC Explains Denial of Rehearing on Cold Weather Standard

FERC provided its promised justification for denying a request to rehear its recently approved cold weather standard, saying the petitioners’ cost recovery concerns were outside the scope of the proceeding (RD23-1).

While the commission’s vote was unanimous, Commissioner James Danly in a concurrence urged a separate investigation into the cost recovery mechanisms established by RTOs and ISOs.

The Electric Power Supply Association (EPSA), the New England Power Generators Association (NEPGA), and the PJM Power Providers Group filed a request for rehearing of EOP-012-1 (Extreme cold weather preparedness and operations), which FERC approved in February along with EOP-011-3 (Emergency operations). That request was denied “by operation of law” in April, when the commission allowed 30 days to pass without action on the request. (See FERC Denies Rehearing of Cold Weather Standard.)

In its follow-up filing last week, the commissioners affirmed that they “continue to reach the same result ” even after considering the petitioners’ arguments.

Petitioners Objected to Cost Burden

EPSA, NEPGA and the PJM group objected to the standard’s requirements for freeze protection measures on new and existing generating units, claiming the measures would require generator owners “to incur potentially significant costs that they lack a reasonable opportunity to recover through rates.” However, FERC declined to address this argument in its implementation order, calling it “outside the scope of the instant proceeding.”

The petitioners responded that by failing to address cost recovery in its order, FERC violated Sections 215 and 219 of the Federal Power Act. They argued the commission should have initiated a proceeding under FPA Section 206 to explore means of cost recovery for compliance with the new standards.

Responding to the cost recovery question, FERC observed that Section 215 says it may approve a proposed standard if the standard is “just, reasonable, not unduly discriminatory or preferential and in the public interest.” It drew a sharp contrast between this part of the act and Section 206, which governs rate proceedings; while both sections use the term “just and reasonable,” FERC said the language in Section 215 clearly does not refer to utilities’ rates.

“While petitioners may have preferred that the commission adopt a specific cost recovery mechanism … the commission’s approval of a reliability standard without such a mechanism does not run afoul of FPA Section 215,” the commission said in its June 29 order. “Nothing in petitioners’ rehearing request suggests that [the standard] is insufficient to protect the reliability of the [grid], which … is the commission’s primary concern in this proceeding.”

Regarding the request for a Section 206 proceeding, FERC said it did not err because Section 215 does not require such actions in connection with reliability standards. Moreover, it pointed out that entities have other means of seeking cost recovery and that nothing in its order affirming the standards prevents them from doing so.

The petitioners also suggested NERC change the standards to require “balancing authorities to ensure sufficient quantities of weather-resilient generation are available, which would then have allowed for the development of rules that would also address cost recovery.” This too was rejected by FERC, which said “nothing in [the] rehearing request suggests that generator owners and … operators are incapable of the duties required under the reliability standard.”

Finally, the commission said Section 219, which “allow[s] the recovery of all costs prudently incurred to comply with the reliability standards,” does not require it to address cost recovery when approving reliability standards, as the petitioners claimed. FERC said utilities that feel they are eligible for cost recovery under this section may do so with “the appropriate filing” and that its order does not preclude such a filing.

Danly Warns of Generation Retirements

In his concurrence, Danly affirmed he supported his fellow commissioners’ decision. However, he warned a Section 206 investigation may be warranted, concerning whether the cost recovery mechanisms used by RTOs and ISOs “can be relied upon to ensure just and reasonable rates.”

Danly said “increasing reliability risk throughout the country” indicates that RTOs and ISOs have not provided the proper incentives for utilities to retain and add the dispatchable generation needed to ride out adverse grid events. He cited a warning from PJM that generation retirement rates are “exceeding the rate of new additions of resources that … we need to manage the grid of the future,” adding that PJM attributed these retirements in part to “diminished energy revenues.”

“Prudence demands that the commission make sure its markets adequately compensate compliance with [reliability] standards in advance of those standards becoming mandatory and enforceable,” Danly said. “Otherwise, sufficient generation may not be available during the next cold weather event. They may have already retired.”

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FERC Denies Rehearing over GridLiance Transmission Recovery

FERC on Wednesday denied a rehearing request over its February decision approving SPP’s tariff revisions that add an annual transmission revenue requirement (ATRR), a formula rate template and implementation protocols for GridLiance High Plains-owned facilities in Nixa, Mo. (ER18-99).

The commission said that according to precedent set by the D.C. Circuit Court of Appeals’ Allegheny Defense Project v. FERC decision, the rehearing request is denied by operation of law. The 2020 order found FERC no longer could grant rehearing requests “for the limited purpose of further consideration.”

FERC did modify the discussion in the February order but continued to reach the same result.

The commission’s order affirmed an administrative law judge’s 2021 decision finding SPP’s proposal to incorporate the Nixa assets into one of its transmission pricing zones was consistent with cost-causation principles and was just and reasonable. (See “Order on GridLiance ATRR,” FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

Several cities in Arkansas and Missouri and a group of SPP transmission owners (Evergy, American Electric Power and Xcel Energy subsidiaries and Western Farmers Electric Cooperative) filed a joint rehearing request in March. They argued that a cost shift associated with a zonal placement decision under SPP’s tariff cannot be just and reasonable unless each customer or group of customers that will bear some portion of the assets’ costs is deriving a benefit from those specific assets that is “roughly proportionate” to those costs.

The commission said it disagreed that rough proportionality is the only appropriate way to approach cost causation under SPP’s zonal placement process. It sustained its decision not to adopt the requirement, saying the intervenors’ approach “does not square with the existing zonal rate construct under the SPP tariff.”

“SPP’s zonal rate construct does not attempt to measure each transmission customer’s benefit from each transmission asset included in the zonal ATRR. Nor does it charge each customer transmission costs on an asset-by-asset basis,” FERC wrote. “Instead, under that zonal construct, the costs and benefits associated with network service in a zone are assessed on an aggregate level, with each customer paying for transmission service based on its load ratio share, which reflects its total use of the aggregate assets in the zone.”

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FERC Clears MISO, SPP’s Affected System Study Improvements

FERC has approved changes to MISO and SPP’s affected system study process to allow either RTO to order upgrades of limiting elements on tie lines.

In a June 30 order, FERC said the revisions to MISO and SPP’s joint operating agreement regarding upgrades to tie line limits and more consistent modeling on SPP’s part should bolster reliability (ER23-1803).

Now MISO or SPP can require all necessary tie line upgrades during the study process, regardless of on what side of the seam the limiting element is located. The upgrade then would be handled under the business practices and tariff of the RTO that has functional control over the limiting element.

Additionally, SPP pledged to conduct its affected system studies using the actual amount of either Network Resource Interconnection Service or the non-firm Energy Resource Interconnection Service requested in MISO by interconnection customers.

The order stems from a complaint EDF Renewables made in 2017 over ambiguous affected system study processes in MISO, PJM and SPP. (See Affected-system Rules Unclear, FERC Says.)

However, MISO and SPP’s JOA revisions could be short-lived, as the RTOs are hoping to ditch their affected system study process in favor of installing regular Joint Targeted Interconnection Queue studies. Both RTOs are readying tariff and JOA language for their first, $1.9 billion portfolio of 345-kV lines meant to bring more generation online at the seams. (See MISO Stakeholders Request JTIQ Cost Containment Measures.)

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NJ’s 1st OSW Project Gets BOEM Seal of Approval

The U.S. Bureau of Ocean Energy Management (BOEM) said Monday it had approved the construction and operations plan for Ørsted’s 1.1-GW Ocean Wind 1 project, New Jersey’s first offshore wind project and the third backed by the Biden administration.

After BOEM released its Record of Decision, the Danish developer said it expects to begin onshore construction in the fall with “offshore construction ramping up in 2024.”

In a release put out by Ørsted, Gov. Phil Murphy called BOEM’s approval “a pivotal inflection point, not just for Ørsted, but for New Jersey’s nation-leading offshore wind industry as a whole.”

The company said the project, located 13 miles from the Jersey coast and with 98 turbines, would power 500,000 homes when it begins commercial operations in 2025.

“Ocean Wind 1 is on the cusp of making history,” said Ørsted Americas CEO David Hardy, adding that the project is set to begin “delivering on the promise of good-paying jobs, local investment and clean energy.”

The project is the third OSW project in the U.S. approved by BOEM, as the nation seeks to reach a goal of 30 GW of wind energy in place by 2030. The other two approved projects are Vineyard Wind off the Massachusetts coast and South Fork Wind off Rhode Island and New York. Both projects recently installed their first monopile foundations, according to the Business Network for Offshore Wind.

“Ocean Wind 1 represents another significant step forward for the offshore wind industry in the United States,” BOEM Director Elizabeth Klein said in a release put out by the Department of the Interior announcing the decision. “The project’s approval demonstrates the federal government’s commitment to developing clean energy and fighting climate change and is a testament to the state of New Jersey’s leadership in supporting sustainable sources of energy and economic development for coastal communities.”

Approvals Still Needed

The announcement comes as Ocean Wind 1 faces continued opposition from OSW opponents who question the cost to the state, say it will hurt the state’s commercial fishing and tourism industries, and have expressed concern about the impact on marine life, especially whales.

Nine dead whales have washed up on the state’s beaches in recent months, but state and federal investigators say there is no evidence that the deaths are related to the developers’ preliminary sonar mapping of the ocean floor. Some of the state’s Republican congressmen have called for a moratorium on the OSW projects until any potential connection between them and the whale deaths is investigated.

Yet the projects have strong support from the state. On Friday, both houses of the Legislature approved a bill that would allow Ocean Wind 1 to reap the benefits of federal tax credits instead of those benefits flowing to the state and helping reduce costs to ratepayers, as is required by New Jersey law. The bill has yet to be signed by Murphy. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)

Stephanie Francoeur, a spokeswoman for Ørsted, said Ocean Wind 1 still needs approval from the Army Corps of Engineers, National Marine Fisheries and EPA.

“All of this is expected by the end of Q2 2024, which allows us to move forward with offshore construction,” she said.

The project already has received “major state permits” from the Department of Environmental Protection (DEP), including a Coastal Area Facility Review Act Permit (CAFRA) and state and federal consistency under the Coastal Zone Management Act. The project already has site plan approval for onshore substations, she said.

Expanding Litigation

Ocean Wind 1 faces two appeals filed against the decision by the state Board of Public Utilities to grant the project an easement over property owned by Cape May County and Ocean City on which to lay underground cables tying the turbines to a nearby substation.

The BPU granted the approval under a new state law that allowed the agency to override local government agencies on an OSW infrastructure issue if it was “reasonably necessary” for the project to advance.

Michael J. Donohue, the attorney for Cape May in the case, said the county is “reviewing the 177 pages and dozens of collateral documents related to the Record of Decision of the Bureau of Ocean Energy Management and other federal agencies released today.”

“Upon completion of that review, the county will determine what avenues for legal challenges, if any, exist to pursue,” he said.

Bruce Afran, a Princeton attorney who filed suit to stop Ocean Wind 1 on behalf of three groups opposing the project, said BOEM’s approval is “by no means a done deal, and the developer of the project is going to face expanding and growing litigation.”

The June 8 suit filed by Afran on behalf of Protect Our Coast NJ, Defend Brigantine Beach and Save Long Beach Island appeals DEP’s finding that the adverse marine impact expected from Ocean Wind 1 did not rise above the level allowed by state law. Afran said he expects to file a suit in federal court against the BOEM decision, saying that the agency’s own environmental impact statement concluded that the project would damage marine life and hurt the tourist industry.

“The approval disregards BOEM’s own findings of significant environmental harm to be caused by this project,” he said.

BOEM’s final, 2,300-page EIS concluded that the project combined with others will have a “major” impact on scenic and visual factors and on scientific research, but only a “moderate” impact on a host of other issues. The study found the impact on scientific research and surveys would be major, as would the cumulative impact of the project and others nearby, including on National Oceanic and Atmospheric Administration surveys that support commercial fisheries and protected species research programs.