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November 16, 2024

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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.

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NM Sets Course to Adopt New Clean Vehicle Rules

New Mexico is about to launch a rulemaking on regulations that would largely mirror California’s ZEV sales requirements, but with one key difference.

Instead of following California’s Advanced Clean Cars II mandate that all new cars sold in the state be zero-emission in model year 2035 and beyond, New Mexico would cap the zero-emission requirement at 82%, starting with model year 2032.

New Mexico is also moving toward zero-emission requirements for trucks, similar to California’s Advanced Clean Trucks rule.

New Mexico Gov. Michelle Lujan Grisham announced Monday that the state plans to enact advanced clean car and clean truck rules. The announcement came during a visit to the Chalmers Ford dealership in Rio Rancho.

“These rules will speed up much-needed investment in New Mexico’s electric vehicle and clean hydrogen fueling infrastructure, create new job opportunities and, most importantly, result in cleaner and healthier air for all New Mexicans to breathe,” Lujan Grisham said.

Advanced Clean Cars and Advanced Clean Trucks would require vehicle manufacturers to deliver an increasing percentage of zero-emission vehicles for sale each year. As proposed, New Mexico’s clean cars rule would start with a 35% ZEV requirement for model year 2026, increasing each year up to an 82% requirement for model year 2032 and beyond.

In contrast, California’s ZEV requirements in Advanced Clean Cars II continue to increase until reaching 100% in model year 2035. California will also allow sales of some plug-in hybrids. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

Requirements under New Mexico’s proposed Advanced Clean Trucks would start with model year 2027 and vary depending on vehicle class. For model year 2035, the zero-emission requirement would be 55% for Class 2b-3 trucks, 75% for Class 4-8, and 40% for Class 7-8 tractors. Those percentages are the same as in California’s Advanced Clean Trucks program.

The proposed rules would apply to automakers, rather than auto dealers or consumers, and would not prohibit the sale or ownership of new or used gas-powered vehicles.

Colorado’s Plan Similar

Environmental advocates who have been urging New Mexico to update its car and truck standards were pleased with Lujan Grisham’s announcement.

“It’s a big step forward,” said Noah Long, a senior attorney with the Natural Resources Defense Council. “Those are really important rules.”

Long said New Mexico’s proposal is similar to an Advanced Clean Cars regulation being considered in Colorado, where increasing ZEV requirements for automakers would stop at 82% in 2032.

NRDC’s analysis has shown “significant benefits” of the rule through 2032, and even more benefits if required ZEV percentages continued to increase. Long noted that the states could amend their regulations to increase stringency in later years.

In addition to Colorado and New Mexico, Maryland, Delaware, New Jersey and Rhode Island are considering adoption of Advanced Clean Cars II this year, according to NRDC. Washington, Oregon, New York, Massachusetts, Virginia and Vermont have already adopted the California program.

Although draft rules have not yet been released, the New Mexico Environment Department posted a fact sheet on the proposed rules that lists the percentage requirements.

The clean cars and trucks rules will be part of the same rulemaking process, which could start as soon as this month, NMED spokesman Matthew Maez told NetZero Insider. The draft rules will generally follow California’s regulations, Maez said, with a few differences.

“The largest difference will be that the proposed rules in New Mexico will culminate in California’s 82% requirement for manufacturers by 2032,” he said.

Availability Issues

In May 2022, New Mexico adopted the Advanced Clean Cars (ACC) regulation, which is based on California’s earlier program. (See NM Adopts Calif. Advanced Clean Cars Rules.)

ACC supporters said at the time that the rule would boost EV availability in New Mexico, where people often struggle to find an electric car to buy. Automakers will prioritize delivery of EVs to the jurisdictions that require them, proponents said.

“These new rules will ensure that all New Mexicans have access to a greater number of new zero- and low-emission vehicle models, while hastening the transition away from polluting diesel and gasoline-powered cars and trucks,” NMED Cabinet Secretary James Kenney said in a statement.

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FERC Approves $1.8M Penalty Against Exelon Utilities

FERC on Friday approved a $1.8 million penalty against Exelon’s utilities, part of a settlement between the subsidiaries and ReliabilityFirst for violations of NERC reliability standards (NP23-17).

NERC submitted the settlement to the commission in a Notice of Penalty on May 31, along with a separate spreadsheet NOP concerning violations of the Critical Infrastructure Protection (CIP) standards (NP23-16). The spreadsheet NOP was not made public because FERC considers CIP violations to be critical energy infrastructure information. FERC said in its Friday filing that it would not further review any of the settlements, leaving the penalty intact.

Exelon utilities Atlantic City Electric (ACE), Delmarva Power and Light (DPL), Pepco, Baltimore Gas and Electric (BGE), Commonwealth Edison and PECO Energy collectively provide electric service to nearly 9 million people in New Jersey, Maryland, Delaware, Virginia, Illinois, Pennsylvania and D.C.

RF’s settlement with the companies stems from violations of FAC-009-1 (establish and communicate facility ratings), which required that transmission owners and generator owners establish facility ratings that are consistent with an established facility ratings methodology. (The standard was replaced in 2013 by FAC-008-3.) The compliance issues were initially identified by ACE, DPL and Pepco; their discovery prompted BGE, ComEd and PECO to conduct investigations, which unearthed their own ratings issues.

ACE kicked off the investigation process in April 2019 after it discovered that it had placed a transmission line back into service without communicating the updated facility rating to PJM. The discovery led ACE to compare more facility ratings against PJM’s records to ensure that all of the RTO’s records were accurate. However, the utility found more inaccuracies in this review, prompting Exelon to expand the scope of the reviews to include DPL and Pepco. Exelon first informed RF of the issues — through the regional entity’s legal team — following this expansion in July 2019.

In December 2019, while the reviews were underway, RF issued an audit notification letter to the utilities. As part of the audit, the RE notified the utilities that they were in violation of FAC-008-3. The review continued through March 2021, when the three utilities identified 235 out of their 349 facilities that required facility rating changes.

BGE, ComEd and PECO reported to RF in July 2020 that they were also in violation of FAC-008-3, having begun their own reviews the year before as a result of the widespread issues discovered by ACE, DPL and Pepco. Their reviews, completed in December 2022, found 278 total misratings across their collective 1,504 facilities.

RF determined that the violations by all six utilities began in June 2007, when FAC-009-1 took effect. They ended in March 2021 in the case of ACE, DPL and Pepco, and in December 2022 for the remaining companies; these dates indicate when the extent of condition reviews were completed and all discrepancies officially corrected.

The RE found that the violations posed a serious risk to grid reliability in the cases of ACE, DPL, Pepco and PECO, and a moderate risk for the other two utilities. Explaining this assessment, RF said that the number of errors and their duration both indicate “a longstanding, systemic issue” with the utilities’ facility ratings practices. It further noted the large adjustments needed in some cases (one facility required a reduction of up to 66%) and that more than a dozen facilities were found to have operated near or above their corrected ratings.

RF attributed the violations to “insufficient internal controls throughout each company’s facility ratings program and processes.” It noted that “multiple teams at various steps” contributed to each utility’s overall facility ratings process, without enough care taken to ensure accurate recording of information at each stage, increasing the potential for human errors.

In the case of the initial three utilities, the RE suggested that a “lack of clear overall ownership and accountability for the … facility ratings program” also exacerbated the risk, along with a lack of formal training for relevant teams. For the remaining utilities, RF found that they had failed to maintain or confirm facility baselines, in some cases relying on baselines developed by third parties that were not adequately reviewed prior to adoption.

ACE, DPL and Pepco committed to more than 25 mitigating activities including implementing additional controls for data accuracy; establishing a new standard repository for relay load limits; committing to regular updates for stakeholders involved in the facility ratings process; and creating a new common facility ratings database. Actions by BGE and the other utilities include completing a full review of the extent of the conditions and implementing a common tool for documenting equipment and facility ratings across all Exelon companies.

RF noted the utilities’ cooperation throughout the process, including their self-disclosure of the suspected noncompliance and their willingness to conduct full physical walkdowns of their facilities “within a relatively short time frame” as reason for mitigating the penalty. On the other hand, the RE said that a previous compliance issue related to FAC-008 served as an aggravating factor in the penalty determination because the utility “failed to identify the full breadth of their systemic issue with facility ratings.”

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DOE to Invest $1 Billion to Build Demand for Clean Hydrogen

The Department of Energy on Wednesday announced plans to use $1 billion from the Infrastructure Investment and Jobs Act to underwrite demand for the clean hydrogen to be produced by the regional hydrogen hubs (H2Hubs) funded with $7 billion from the law.

The goal of the proposed “demand-side support mechanism” will be to “ensure both producers and end users in the H2Hubs have the market certainty they need in the early years to unlock private investment and realize the full potential of clean hydrogen,” according to DOE’s press release.

A combined notice of intent (NOI) and request for information (RFI) also released Wednesday outlined several options for how the money might be used. For example, DOE might act as a “market maker,” buying clean hydrogen from the hubs and then selling it to offtakers. Other options might include:

    • “Pay-for-difference” contracts that provide support to projects based on current market prices;
    • A fixed level of support for projects ― for example, a fixed amount per kilogram ― added on top of other sources of revenue; and
    • Funding to support feasibility studies undertaken by potential offtakers near the H2Hubs.

“Ensuring America is the global leader in the next generation of clean energy technologies requires all of us — government and industry — coming together to confront shared challenges, particularly lack of market certainty for clean hydrogen,” Energy Secretary Jennifer Granholm said in the press release. “That’s why DOE is setting up a new initiative to help our private sector partners address bottlenecks and other project impediments — helping industry unlock the full potential of this incredibly versatile energy resource and supporting the long-term success of the H2hubs.”

The RFI also asked for industry input on how hubs or companies might apply for the demand-support funds. The options here range from a reverse auction, with projects bidding in the lowest amount needed to make a project viable, to an “eligibility-based process,” in which all projects meeting certain threshold criteria would receive some form of support.

Another key question is whether an independent entity should administer the program.

Final applications for the regional H2Hubs were due April 7, and according to DOE’s Office of Clean Energy Demonstrations, which is overseeing the initiative, six to 10 hubs will be selected for funding by the end of the year. DOE will accept comments on the NOI-RFI through July 24 and expects to issue a “broad agency announcement” for the initiative by early fall.

A broad agency announcement is similar to a request for proposals but does not define a specific project. Rather, it poses a problem and invites proposals for different solutions.

Demand Lags Supply

President Joe Biden and DOE have framed clean hydrogen and the H2Hubs as essential for addressing hard-to-decarbonize industrial sectors, such as cement, steel and heavy-duty trucking.

The hydrogen hubs, to be located in diverse geographic regions across the country, are intended to kick-start the U.S. market, and the initiative drew a range of applications, some with two or more states partnering on a project. The Inflation Reduction Act backs up the hubs with a production tax credit of up to $3/kg for clean hydrogen, creating a strong draw for foreign investment as well.

So, with that level of support, why is further investment needed?

DOE’s Pathways to Commercial Liftoff Report for clean hydrogen, released this year, puts securing long-term offtake contracts at the top of its list of challenges to commercialization.

“At present, producers struggle to find credit-worthy offtakers with sufficient hydrogen demand sited within an affordable distance to hydrogen production who are willing to sign long-term contracts,” the report says. “Many offtakers with near-term break-even points are refineries and ammonia production facilities that can retrofit their existing facilities with carbon capture and sequestration rather than seek out a new clean hydrogen producer.”

Speaking at a recent event at the Bipartisan Policy Center in Washington, D.C., David Crane, DOE’s undersecretary for infrastructure, teased Wednesday’s announcement, saying that while the IRA did a good job of incentivizing supply, “the history of energy … is that demand formation always lags supply.” (See DOE Under Secretary: Industrial Decarb Should Happen This Decade.)

Building demand is a priority for the White House and DOE, he said.

The Liftoff report details other challenges for demand-building, such as the inability of offtakers to hedge any price volatility. Another concern for offtakers is that without a broad national supply chain, amounts of clean hydrogen may be insufficient or variable.

Crane sees the hubs as a first step to the buildout of both production and distribution facilities across the country that will support new applications for clean hydrogen and bolster offtaker and investor confidence.

As outlined in the RFI, the ultimate goal for the demand-support initiative is “the formation of a mature commodity market for clean hydrogen,” based on price transparency and standard, long-term contracts.

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Massachusetts DPU Greenlights Major Battery Projects After Delays

The Massachusetts Department of Public Utilities has cleared the way for construction of two major battery facilities that would get the state most of the way to its 2025 energy storage goals.

After an extended planning and review process, the Medway (Mass DPU 22-59) and Cranberry Point (Mass DPU 22-18) projects suffered setbacks when the state Energy Facilities Siting Board (EFSB) decided May 11 that it lacked jurisdiction over battery energy system storage (BESS) proposals because they were not energy generation facilities.

That move sent the proposals to the DPU for review. This, combined with earlier delays, made developers fear they would miss their contractual obligation with ISO-NE to come online by June 1, 2024, potentially opening them to millions of dollars in penalties.

On Friday, the DPU issued rulings exempting the two projects from local zoning rules, effectively greenlighting both, though with a lengthy list of conditions on design and construction.

In an email to NetZero Insider this week, Plus Power, which owns the LLC developing Cranberry Point, declined to predict whether it could pull permits and start and finish construction in 11 months.

But CEO Brandon Keefe said: “We thank Massachusetts’ leadership for making this decision based on the facts of regional need, project design, minimal environmental footprint and safety best practices. Battery energy storage is already widely deployed across the country to help decarbonize and modernize electric grids. The Cranberry Point Energy Storage project will be a critically important asset to improve power reliability and clean electricity for Southeast Massachusetts.”

Cranberry Point Energy Storage is a 150-MW/300-MWh BESS proposed by Plus Power in Carver, northeast of Fall River; a short overhead power line to an existing substation is part of the project.

Medway Grid Energy Storage System is a 250-MW/500-MWh BESS proposed by Eolian Energy in Medway, northwest of Fall River. The project also includes an underground line running to an existing substation.

Together, they would provide 80% of the 1,000-MWh goal Massachusetts has set for Dec. 31, 2025, under its Energy Storage Initiative.

Large-scale storage is expected to play a critical role in the clean energy transition as the grid increasingly relies on intermittent generation resources and traditional patterns of electric consumption change.

‘Different World’

The long-running deliberation by the EFSB was a source of frustration for the developers of the two projects but was not fruitless: The extensive record it established enabled DPU to move quickly on the proposals.

However, the matter also highlighted the need to revise decades-old regulatory language codified long before utility-scale energy storage was contemplated.

When the EFSB punted to the DPU, a spokesperson for Gov. Maura Healey’s Office of Energy and Environmental Affairs addressed this shortcoming, telling NetZero Insider the EFSB is guided by statute.

“As the case before the board today demonstrates, that statute was designed for a different time when the power system was based on large fossil fuel power plants owned by utilities. Today, we live in a different world,” the spokesperson said. “This is why EEA Secretary [Rebecca] Tepper established a commission on permitting and siting to assess and address the jurisdiction around building large amounts of renewables in an equitable manner. It is critical that we as a state review our regulatory scheme to ensure we can site the renewables that we need to meet our energy and climate goals.”

BESS facilities have a lower profile than some other components of a carbon-free power grid, with none of the imposing height of wind turbines and horizontal sprawl of solar arrays. But a spate of intense fires in consumer-scale lithium batteries has prompted pushback from residents who live near proposed BESS sites and are worried that utility-scale lithium battery systems pose an exponentially larger threat than e-bike batteries.

The similarities between the two types of batteries start and end at the word “lithium,” but that distinction can be lost on people who do not work in the battery or firefighting industries.

The DPU addresses safety concerns in conditions it sets for construction of Cranberry Point and Medway, which require developers to:

      • update the DPU regularly on completion of their hazard mitigation analyses and emergency response plans;
      • detail in those plans the personnel, equipment and apparatus required to respond to a significant thermal event;
      • work with the local fire departments on providing real-time notification to nearby residents;
      • develop an evacuation and/or shelter-in-place protocol during emergencies;
      • report to the DPU within seven days any incident that requires fire department notification; and
      • comply with state regulations on PFAS.

Also, the companies must submit plans to ensure that any firefighting water is fully contained in stormwater basins and does not discharge from the basin or otherwise seep into the ground. The DPU directed them to submit a plan to collect and test samples of the water and report the results back to the DPU.

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FERC Affirms Affiliate Status of Evergy, Bluescape

FERC affirmed Evergy’s status Monday as an affiliate of Bluescape Energy Partners, rebuffing rehearing requests from the Kansas City utility and the Edison Electric Institute (ER20-67).

The commission cited the 2020 Allegheny Defense Project v. FERC decision in denying the rehearing requests “by operation of law.” The D.C. Circuit Court of Appeals’ ruling in Allegheny found FERC no longer could grant rehearing requests “for the limited purpose of further consideration.”

Evergy’s operating companies filed a change in status with the commission in 2020, reflecting a change in their upstream ownership when Evergy’s leadership said it would remain a standalone company after pursuing purchase offers. In February 2021, Dallas-based Bluescape said it was investing $155 million in Evergy and, in return, gaining two seats on its Board of Directors.

Last October, FERC issued an order finding Evergy and its subsidiaries are Bluescape affiliates by virtue of the board’s new membership. The commission found that Evergy’s appointment of Bluescape executive chairman C. John Wilder as an independent director to its board to be a “concern” it previously had expressed in a proceeding involving CenterPoint Energy.

C. John Wilder | C. John Wilder via LinkedIn

FERC also clarified that placing non-independent officers or directors on a utility’s board of directors or its holding company — regardless of whether the ownership stake is 10% or more of the utility or its holding company — qualifies the entity placing those directors as an affiliate of the public utility. (See FERC Clarifies When Board Appointees Make Companies Affiliates.)

Evergy filed its rehearing request in November, alleging FERC’s order contradicted its affiliate definition by not representing an independent basis from which to find affiliation and because its interpretation “confused the function of a rebuttable presumption.” (The commission’s definition of affiliate provides those “owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.”)

“If an entity owns less than 10%, it need make no further showing; unless an opponent adduces some evidence going to control, the issue is settled in favor of no control,” the company argued. “If, however, [the commission] or a protestor adduces sufficient evidence that an entity controls a public utility despite owning less than 10%, the result is to rebut the presumption, i.e., to eliminate the presumption. But that’s not what FERC’s order does. FERC treats rebuttal as resolving the issue in favor of control.”

FERC said it continued to find Wilder’s appointment “overcomes the rebuttable presumption of a lack of control” under its affiliate regulations. It also said the appointment is a per se finding of control “further supported by other aspects of Bluescape’s ownership of Evergy.”

“This indicates … ‘there is liable to be an absence of arm’s-length bargaining in transactions between’ Bluescape and Evergy ‘as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that [Bluescape] be treated as an affiliate’” the commissioners said in the order.

FERC’s acting chair, Willie Phillips, concurred with the order but also said that the commission should have opened a Section 206 proceeding under the Federal Power Act or asked for further briefing.

“Perhaps after briefing we would reach the same result; perhaps not,” he wrote. “Either way, that process would have allowed us to fairly examine what is an issue of first impression before the [c]ommission, helping ensure we reach legally durable results when exercising such an important aspect of our authority.”

Commissioner James Danly dissented, saying the order failed to “fully and adequately” respond to Evergy’s arguments raised in its rehearing request.

“It violates the Administrative Procedure Act,” he said, referring to the process by which federal agencies develop and issue regulations.

EEI’s rehearing request was dismissed after FERC rejected its late intervention motion, saying it failed to demonstrate good cause to intervene out-of-time. The commission ruled EEI was not a party to the proceeding.

Hearing Set for Evergy Asset Recovery

FERC last week accepted SPP‘s filing on behalf of Evergy Kansas Central (Evergy KC) and Evergy Kansas South to establish regulatory assets and recover their unamortized balance through its tariff. The June 30 order was effective July 1, subject to refund, and established hearing and settlement judge procedures (ER23-1762).

The commission said its preliminary analysis found that Evergy’s and SPP’s filings have not been shown to be just and reasonable and may be otherwise unlawful. It said the filings raise issues of material fact more appropriately addressed in the hearing and settlement judge procedures. The hearing will be held in abeyance to provide time for settlement judge procedures.

Evergy KC requested FERC approval to establish three regulatory assets: catalyst costs, generation baghouse costs and critical infrastructure and cybersecurity costs. It also asked for approval to recover the unamortized balances for the assets’ costs incurred in 2019.

Kansas Electric Power Cooperative (KEPCo) filed a formal challenge and complaint in November 2020 against Evergy KC’s annual update to its rate schedule. It argued that the utility had included several regulatory assets’ amortization expenses in the update without commission approval.

FERC in April 2021 granted the complaint and directed Evergy KC to remove from the formula rate inputs any amounts that represented the recovery of the costs. Evergy KC and Evergy Kansas South made a subsequent filing in a separate docket (ER22-1657) that again requested approval to establish the regulatory assets and recover the unamortized balance. FERC accepted the request, suspending it for a nominal period and establishing hearing and settlement judge proceedings.

Evergy KC made another filing to reverse the regulatory asset and immediately record and recover those costs as current operating expenses. FERC rejected that request in October 2022, but Evergy requested a rehearing.

The commission affirmed its finding in February but held that to “the extent … Evergy KC chooses to make an FPA section 205 filing seeking approval to recover the 2019 regulatory-asset related expenses in rates, the [c]ommission will evaluate its filing consistent with [c]ommission precedent.”

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NYSERDA Asks PSC to Revise REC Capacity Price Calculations

The New York State Research and Development Authority last week petitioned the state’s Public Service Commission to adjust how it calculates the reference capacity price (RCP) for renewable energy certificates to account for NYISO’s new capacity accreditation construct (18-E-0071/15-E-0302).

The RCP is an input used to calculate how much generators who own index REC contracts are paid each month. The price, along with a reference energy price, is subtracted from the index strike price to determine the total amount paid. Thus, the lower the RCP, the higher the revenue.

NYSERDA told the PSC that some intermittent generators were having difficulty predicting the amount of capacity revenue they expected to receive because of the changes. The agency proposed eliminating the need for generators to predict their unforced capacity (UCAP) production factor, itself an input in the calculation for the RCP, and change the variable to a fixed value, unless a generator requests a specific value and the commission approves it.

“Eliminating the need for [REC bidders] to predict future UCAP amounts would reduce the risk associated with future variance between a resource’s capacity revenue and reference capacity price,” NYSERDA wrote.

But while “the proposed revised reference capacity price formula provides a more flexible and resilient hedge and is therefore expected to lower bid prices in future” requests for proposals, NYSERDA cautioned that it “is not able to reasonably predict the associated reduction in ratepayer costs.”

NYISO received FERC approval in 2022 to adopt a new marginal capacity accreditation market design that placed more value on intermittent suppliers and generators providing marginal contribution to reliability, instead of their average contribution. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.) The new rules are scheduled to become effective May 1, 2024.