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November 14, 2024

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Members Press NERC to Expand Comments on IBR Standards

Members of NERC’s Standards Committee moved forward a slate of standards development projects at their monthly conference call Wednesday after moving to address concerns about stakeholders’ ability to provide feedback.

The biggest debate revolved around the first standards action, which proposed to accept a draft standard authorization request (SAR) to revise reliability standard EOP-004-4 (Event reporting) to ensure that events involving inverter-based resources (IBR) are reported to regional entities or other responsible authorities.

The SAR was developed in response to NERC and WECC’s joint white paper on the widespread reduction of solar output in Southern California on July 7, 2020. NERC’s Reliability and Security Technical Committee (RSTC) endorsed the draft SAR at its meeting on Dec. 6. (See “Members Approve IRPS SARs,” NERC RSTC Briefs: Dec. 6-7, 2022.)

The action before the committee on Wednesday was to accept the draft SAR and authorize NERC to solicit SAR drafting team members and post the proposal for a 30-day informal comment period. However, Southern Co.’s Jim Howell, noting “some feedback from my segment [over] concerns with what this might involve,” suggested modifying the proposal to post the SAR for a formal, rather than informal, comment period.

Latrice Harkness, NERC’s manager of standards development, responded that a formal comment period was unnecessary because industry already had a chance to influence the draft SAR when it was before the RSTC. She added that a formal comment period would require the SAR drafting team to provide a response to stakeholders when it returns to the committee with the final SAR. This would not be required for an informal comment period.

In either case, the team would not be required to revise the SAR in response to comments.

Howell insisted that the committee should err toward giving as many opportunities for industry input as possible.

“There’s still quite a bit of folks not necessarily plugged in to those committees that may have some valid comments about the SAR itself,” Howell said. “I do think [we] would be better served to have a formal comment period where there’s more interaction between the drafting team and the comments up front.”

Marty Hostler, reliability compliance manager for Northern California Power Agency, supported Howell’s proposal, saying that “there are just a host of initiatives out there by FERC [and] NERC on IBRs,” and that it would be inappropriate to move forward with yet another standards project “until we get all these other comments in … from the other IBR initiatives.”

Hostler said a formal comment period would provide a chance “to have industry vet what their opinions are.” Kent Feliks of American Electric Power and William Chambliss of the Virginia State Corporation Commission also voiced support for the idea, with Chambliss seconding Howell’s formal motion to switch from an informal to a formal comment period. The motion passed the committee unanimously.

Other Standards Actions

The committee’s next item also concerned IBRs, with a proposal to accept a draft SAR to “address IBR performance issues” either by creating a new standard or by modifying PRC-004-6 (Protection system misoperation identification and correction).

Like the earlier draft SAR, this proposal was also endorsed by the RSTC at its December meeting. Hostler again expressed misgivings about the SAR, asking why the committee needed to consider two separate projects both intended to address IBRs. Vice Chair Todd Bennett, of Associated Electric Cooperative Inc., responded that the two SARs had very different goals, with the former intended to address reporting of IBR-related incidents and the latter intended to mitigate performance issues within IBRs once they have been detected.

Aside from Hostler’s questions, few misgivings were expressed for this item. Howell explained that he was “not so concerned” about requiring a formal comment period because there is already “a lot of … good information out there from the industry on what this would entail.” The committee voted unanimously to accept the SAR, appoint the drafting team and authorize posting for an informal comment period.

Next up was a proposal to accept two SARs requiring registered entities to perform energy reliability assessments to ensure energy assurance. The SARs were proposed by NERC’s Energy Reliability Assessment Task Force (ERATF) last year and assigned to Project 2022-3 (Energy assurance with energy-constrained resources) at the Standards Committee’s September meeting. Harkness explained that the ERATF and SAR drafting team proposed two SARs to cover risks associated with the operational and planning time horizons separately.

Chambliss abstained from the vote, explaining that “all this work occurred before I got on the committee, and I hadn’t really had a chance to familiarize myself with it.” The proposal — which included appointing the 15 members of the SAR drafting team as the standard drafting team as well as accepting the SAR — otherwise passed without objection.

Also approved without objection was a proposal to appoint the SAR drafting team, including chair and vice chair for Project 2022-05 (Modifications to CIP-008 reporting threshold). The project was also approved at the committee’s September meeting; NERC solicited industry for nominations to the team from Nov. 2 through Dec. 5, receiving 10 nominations whose names were not disclosed at Wednesday’s meeting in accordance with the organization’s confidentiality policy.

Finally, the committee approved a motion to update NERC’s definition of reporting area control error (ACE) as proposed by Project 2022-01 (Reporting ACE definition and related terms). The new definition expands the list of relevant entities and changes certain language to reflect updated NERC terminology.

While no committee members voted against the measure, Robert Blohm of Keen Resources abstained from the vote. He said he was concerned about the committee’s inability to review the final comment form before it is posted, mentioning that he had already expressed misgivings about the lack of questions regarding the definition of ACE Diversity Interchange. Describing this absence as “a serious technical error … that could affect the acceptability” of the ballot outcome, Blohm said he could not “in good conscience” support the motion.

Members Approve Executive Committee Slate

In addition to their standards actions, attendees approved the membership of the Standards Committee’s Executive Committee (EC) for 2023, to serve one-year terms.

According to the Standards Committee’s charter, the EC is to comprise five members including the chair and vice chair — currently Amy Casuscelli of Xcel Energy and Bennett, respectively. At its last meeting, the committee invited those interested in one of the three remaining seats to submit their nominations by Jan. 9. (See “2023 Executive Committee Nominations,” NERC Standards Committee Briefs: Dec. 13, 2022.)

Three committee members nominated themselves prior to the meeting: Venona Greaff of Occidental Chemical, Sarah Snow of Cooperative Energy and Charles Yeung of SPP. Troy Brumfield, regulatory compliance manager at American Transmission, also threw his hat in during the meeting. Members chose Brumfield, Greaff and Snow in the final vote. Bennett thanked the new EC members and encouraged others “to get involved with this committee as much or as little as they like.”

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Tesla to Invest $3.6B in Nev. Truck, Battery Factories

Tesla plans $3.6 billion of additional investment in Northern Nevada, including a new battery factory and its first high-volume manufacturing facility for electric semi-trucks, the company announced Tuesday.

“We will be investing over $3.6 billion more to continue growing Gigafactory Nevada, adding 3,000 new team members and two new factories,” Tesla (NASDAQ:TSLA) said in a blog post. Tesla’s Gigafactory Nevada is a 5.4 million square-foot facility east of Reno.

The new battery factory will have the capacity to produce enough batteries for 2 million light-duty vehicles a year, the company said.

The electric truck factory will make Tesla’s Semi model, which the company describes as a fully electric, 18-wheel truck capable of trips up to 500 miles. Semi uses less than 2 kWh of energy per mile, Tesla said.

Tesla’s first delivery of the Semi was to Pepsi last month.

The White House weighed in Tuesday on Tesla’s announcement.

“The manufacturing boom of President Biden’s first two years continues today with Tesla’s announcement that they will invest more than $3.6 billion in battery and electric semi-truck manufacturing in Sparks, Nevada,” White House Infrastructure Coordinator Mitch Landrieu said in a statement provided to NetZero Insider.

“This announcement is the latest in more than $300 billion in private sector investment in clean energy and semiconductor manufacturing announced since the president took office,” Landrieu added. “It will create more than 3,000 good-paying jobs in Nevada helping America lead in clean energy manufacturing, strengthening our energy security, and ultimately lowering costs for families.”

Nevada Gov. Joe Lombardo briefly mentioned the new factory in his State of the State address on Monday, while discussing his plans to restore Nevada’s reputation as a pro-business state.

“I’m looking forward to joining Elon Musk and the team at Tesla tomorrow when they unveil plans to build a brand-new $3.5 billion-dollar advanced manufacturing facility in Northern Nevada for the company’s all-electric semi-trucks,” Lombardo said during the speech.

Tesla said it has invested $6.2 billion in Nevada since 2014. Production at Gigafactory Nevada has included 7.3 billion battery cells, 1.5 million battery packs and 3.6 million drive units.

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FERC Rejects GridLiance, AECI Rehearing Requests

FERC last week dismissed as moot GridLiance High Plains’ request to rehear last year’s ruling that the utility failed to prove that certain Oklahoma facilities were eligible for cost recovery as transmission infrastructure and not distribution-related infrastructure (ER18-2358).

The commission said Thursday it was not persuaded by GridLiance’s assertions that FERC inappropriately shifted to the utility the burden of proof to demonstrate that its facilities are transmission facilities under Order 888’s seven-factor test.

GridLiance filed its request in October after FERC affirmed in part and reversed in part an administrative law judge’s previous decision in hearing and settlement procedures addressing SPP’s proposal to revise its tariff to incorporate an annual transmission revenue requirement. The change would have placed the Oklahoma Panhandle facilities into Southwest Public Service’s transmission pricing zone. (See “Commission Rejects SPP Tariff Revision, Reversing ALJ Decision,” FERC Revokes Tri-State’s Market-based Rate Authority in WACM.)

GridLiance argued that FERC erred by putting the burden of proof on the utility. It said it satisfied that burden when it showed “by a preponderance of evidence” that the facilities are transmission facilities under SPP’s tariff and were appropriately classified. The commission’s interpretation “silently subsum[es]” the seven-factor test and contradicts SPP’s filed tariff by adding certain conditions, GridLiance said.

But the commission said it was not persuaded, noting it had already rejected the same argument last year and finding that GridLiance did not provide a “persuasive reason” to revisit its decision. It continued to find that under the Federal Power Act’s burden-of-proof framework and FERC precedent that requiring Xcel Energy, SPS’ parent company, to carry the seven-factor burden of proof would “effectively shift the onus” from SPP and GridLiance.

“SPP and GridLiance … bore the ultimate burden of persuasion with respect to the filing,” FERC said. “Classification of the GridLiance facilities as transmission facilities was an integral component of that filing, and the commission has established that the seven-factor test may be applied for the purpose of that classification.”

FERC did grant GridLiance’s request for clarification, saying the facilities may continue to be classified as distribution facilities. It said the proceeding did not demonstrate that upgrades to the facilities changed their classification.

Commission Sustains Order in AECI Proceeding

The commission also rejected a rehearing request from Associated Electric Cooperative Inc. (AECI), sustaining a 2022 order that found the commission was appropriate in exercising primary jurisdiction over SPP’s sales of emergency energy during February 2021’s winter storm (EL22-54).

FERC again found that SPP properly compensated AECI and that the transactions were made under a commission-jurisdictional tariff. (See FERC Rules for SPP in AECI Dispute.)

The co-op appealed the decision in September, arguing that FERC ignored evidence of oral agreements between the parties that led to AECI responding to the SPP’s verbal requests for emergency power during the storm. It said the commission relied on “post hoc rationalizations” in labeling the emergency transactions as market transactions.

FERC disagreed, saying the SPP tariff, the AECI-SPP joint operating agreement and AECI’s market participant agreement constituted the “filed rate applicable” to energy transactions, making the co-op’s status as a neighboring BA “irrelevant” in determining whether it is bound by those agreements.

“Assum[ing] a rate would be charged other than the rate adopted by” the commission would violate the filed rate doctrine, the commissioners wrote.

The commission dismissed AECI’s argument that FERC erred in granting SPP’s petition that FERC issue a declaratory order to declare that the grid operator had paid AECI the “full, correct and only legally permissible rate” for the emergency power.

FERC reiterated that it is appropriate for the commission to exercise primary jurisdiction over the transactions as it followed precedent and has the appropriate “expertise” to make such decisions.

“The commission has special expertise interpreting jurisdictional wholesale rates like SPP’s tariff, the AECI-SPP JOA and the AECI MP Agreement because [it] oversees the rules governing wholesale markets like SPP’s Integrated Marketplace … and is therefore best positioned to understand the meaning of the terms and conditions in the filed rate,” FERC said.

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DC Circuit Upholds FERC’s Refund Order in Ameren Illinois Case

A three-judge panel of the D.C. Circuit Court of Appeals on Tuesday upheld FERC’s decision requiring Ameren Illinois to refund inappropriately recovered costs related to transmission construction.

The utility improperly included costs for construction-related supplies and materials in the same filing that was meant to recover the cost of transmission plant materials and supplies, when the construction supplies were not eligible to be recovered under the formula rates Ameren Illinois was using at the time.

“The commission found that Ameren Illinois had misreported materials and supplies costs on Form 1 and ordered Ameren Illinois to pay approximately $11.5 million in refunds to its customers, based on ten years of misreporting,” the court said (20-1277).

Ameren filed for rehearing, which was rejected by FERC (ER20-1237). The company appealed to the D.C. Circuit, which said that FERC has broad statutory authority to grant refunds.

“Upon finding that Ameren Illinois failed to correctly record certain materials and supplies costs in the annual Form 1 report, the commission reasonably determined, based on a balancing of the equities, that refunds were warranted,” the court said.

Ameren argued that FERC issued its customers a “windfall” and failed to perform a required balancing-of-equities test in granting the refund, but the court disagreed.

The utility said reporting construction-related costs in the wrong line was a common industry practice before FERC found Duke Energy Progress doing the same and put the industry on notice that it needed to stop the practice. That means it should not be bound its formula rate, Ameren said.

“No justification is offered for that position,” the court said. “The utility’s view that the misreporting was a mere technicality ignores the fact that such costs, if properly reported at line 5, could not have been passed on to customers under Ameren Illinois’s formula rate.”

Rather than giving customers a windfall, Ameren’s error resulted in a windfall for itself to the tune of $11.5 million. That amounts more than a ministerial error, the court said.

Just because FERC has not issued a refund order for every other utility that listed the construction-related costs under the wrong item does not mean the refund order to Ameren was unjust and unreasonable, the court said.

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CARB Examining Obstacles on Road to ZEV Fleet Adoption

As the California Air Resources Board moves closer to adopting a regulation requiring truck fleets to transition to zero-emission vehicles, the agency is looking at how to handle situations where supporting infrastructure is not available.

The CARB board held a hearing on the regulation, known as Advanced Clean Fleets (ACF), in October. The regulation is expected to return to the board for final adoption this spring.

The proposed regulation covers three types of fleets: drayage trucks; state and local government fleets; and federal and high priority fleets, defined as fleets of 50 or more trucks or owned by a business with $50 million or more in annual revenue.

The regulation would require new trucks added to drayage and high priority fleets to be zero emission starting in January 2024. For state and local fleets, half of new trucks could be gas-powered until January 2027, at which time all fleet additions would need to be zero emission.

But CARB recognizes that some fleet operators might not be able to acquire the new ZEVs on schedule — or have infrastructure in place to charge them — due to factors beyond their control.

“If the infrastructure is not available, it doesn’t matter how many vehicles we have in our parking lot,” CARB Vice Chair Sandra Berg said during an ACF workshop this month. “Likewise, if the vehicles aren’t available, it doesn’t matter how many we can plug in at the facility.”

CARB held the workshop to discuss expanding exemptions to ACF when vehicles or infrastructure aren’t available.

In cases where a ZEV is not commercially available in the configuration needed, the draft regulation would allow a fleet operator to buy a gas-powered vehicle instead. If a ZEV is ordered a year ahead of the compliance deadline but delivery is delayed, the operator can keep using their internal combustion vehicle until the ZEV arrives.

On the infrastructure side, a compliance extension of up to two years would be offered in cases where there’s a construction delay. That might be a change in general contractor, unexpected safety issues, or a shipping delay for the zero-emission charging or fueling equipment.

The two-year extension is an increase from the previously proposed one year. The extension would be available if construction started at least a year before the compliance deadline.

Utility Delays Considered

And in a new proposal discussed during this month’s workshop, a compliance extension of up to five years could be granted if a contract has been signed with a utility to power the infrastructure, but the utility needs more time to finish the job. The provision would apply to power needed for electric charging or, in the case of hydrogen fuel cell vehicles, electrolyzers to produce the hydrogen.

Another new proposal from CARB is to post online details on granted extensions, such as the reason for the extension and its length, the city where the fleet is located, and the number of ZEVs involved.

Some workshop participants said CARB should allow compliance extensions in a wider variety of situations. One example is when infrastructure installation is delayed due to prolonged negotiations with a landlord over site improvements. Delays due to California Environmental Quality Act issues was another example.

Others said there should be no time limit on the exemptions.

“The infrastructure exemption should last as long as needed. What happens if you hardwire-in two years into the rule and it doesn’t happen?” said Jon Costantino, a consultant representing the California Council for Environmental and Economic Balance. “There needs to be an opportunity to deal with … the outliers.”

But “we can’t have an open-ended process of extensions,” Berg said.

“We have to put the marker in the sand,” she said. “It has to be clear. It has to be enforceable. And it has to have provisions for flexibility that work within the guidelines.”

Speeding the ZEV Transition

Advanced Clean Fleets is a complement to CARB’s Advanced Clean Trucks regulation, adopted in 2020, which requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles starting in 2024.

Several other states, including Washington, Oregon, Massachusetts, New Jersey, New York and Vermont, have adopted an Advanced Clean Trucks regulation, and other states are considering doing so.

ACF tackles the ZEV transition from a different angle, targeting truck fleets that could transition to zero-emission vehicles relatively soon, the agency said.

“The proposed ACF regulation attempts to strike a balance between moving the market quickly to ZE while recognizing fleets more suited for electrification should lead the way for smaller fleets,” CARB said in its initial statement of reasons for the rule.

The proposed ACF regulation would require all medium- and heavy-duty trucks sold in the state to be zero-emission starting in 2040, and all drayage trucks to be ZEVs by 2035.

At the Oct. 27 hearing on ACF, CARB board members asked staff to fine-tune the regulation, including changes to better address delays in availability of ZEVs or charging infrastructure.

Since then, the agency has held a series of workshops on proposed modifications. Another workshop is scheduled for Feb. 13.

CARB then plans to release a package of changes to the proposed regulation for a 15-day comment period before ACF goes to the board for final approval.

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Comments Show Battle Lines over ISO-NE Interconnection Costs

New England transmission owners have asked FERC to dismiss a RENEW Northeast complaint that seeks to shift the burden of network upgrade operations and maintenance costs off interconnection customers.

In the complaint, the renewables group argued that ISO-NE
is the only U.S. region in which interconnection customers are directly assigned costs for the capital and O&M needed for network upgrades, an “exemption” from FERC policy that RENEW said is unjust and unreasonable. (See Renewable Group Asks FERC for Interconnection Cost Changes in NE.)

In its response, ISO-NE asked to be dismissed from the complaint because the provisions under discussion are transmission rate terms under control of the transmission owners and in which the grid operator doesn’t hold any financial interest.

The transmission owners offered a more substantive answer, arguing that the complaint “fails to meet RENEW’s [Federal Power Act] Section 206 burden of proving that the tariff rate on file is unjust and unreasonable.”

The TO’s argue that generators paying for network upgrades is part of a “grand bargain” that also includes “free and unlimited open access to regional network transmission service on the ISO-NE system.”

It’s a deal that has been subject to FERC review several times and been repeatedly accepted by the commission, the TOs wrote.

They also argue that altering a single aspect of cost allocation for the region’s system could place the entire structure in “jeopardy,” which is why FERC has a “stated policy against unilateral changes to a single aspect of a comprehensive negotiated rate structure.”

Other Corners Respond 

New England’s generators, unsurprisingly, backed the RENEW complaint.

The New England Power Generators Association (NEPGA) described in its comments the “negative impact this unlawful assignment of O&M costs has on competitive market outcomes.” NEPGA noted that market participants can’t recover the O&M costs in the capacity or energy markets.

“The shifting of costs RENEW highlights creates broad negative economic consequences both for resources that rely on markets to produce economic outcomes and those that pay for their services,” the association wrote.

Likewise, in a joint comment, the renewable and clean energy groups Advanced Energy United and the Northeast Clean Energy Council supported RENEW’s complaint, saying the direct assignment charges at issue “unduly burden interconnection customers” that are currently most heavily represented by renewable and storage developers.

“Directly assigning O&M network upgrade costs to interconnection customers clearly violates FERC’s O&M cost policy and the ‘beneficiary pays’ rule of cost allocation and should not be sustained,” the groups wrote.

Among those weighing in against the RENEW complaint were the New England states (as represented by New England States Committee on Electricity) and newly appointed Massachusetts Attorney General Andrea Campbell. Both argued that the complaint would shift costs unfairly onto ratepayers.

“RENEW seeks to replace long-settled rules that put development risks and costs on interconnection customers with a one-sided bargain that shifts 100% of those costs to consumers,” NESCOE wrote in its comment. “The commission should reject that myopic approach, as both bad policy and a matter of law.”

Campbell’s comment pointed to precedent, including past commission rulings and failure of a similar proposal in the NEPOOL process, to argue against the complaint in addition to expressing worries about the costs for consumers.  

“New England ratepayers … already pay higher transmission costs than customers in any region in the United States,” the AG wrote. “To grant RENEW’s cost shifting remedy would only exacerbate New England ratepayers’ already high transmission rates.”

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ERO Praises ERCOT’s Actions to Address Inverter Incidents

Staff from NERC and the Texas Reliability Entity commended ERCOT in a webinar Tuesday for its “extremely proactive approach” to mitigating the challenges exposed by the Odessa disturbances of 2021 and 2022, while reminding listeners that more work is needed across the ERO Enterprise to overcome the underlying issues.

The webinar was part of Texas RE’s monthly “Talk with Texas RE” series, in which presenters from the regional entity discuss ongoing and emerging reliability challenges in both the Texas Interconnection and the broader bulk electric system. Patrick Gravois, an electrical engineer at ERCOT, and Rich Bauer with NERC’s event analysis division joined David Penney of Texas RE in a discussion that built on the report that NERC and the RE released last year on the 2022 Odessa disturbance. (See NERC Repeats IBR Warnings After Second Odessa Event.)

The Odessa events occurred about a year apart near the town of Odessa, Texas. Both were initiated by faults at synchronous generation plants and resulted in the loss of significant amounts of solar PV and synchronous generation, with a reduction of 1,340 MW in 2021 and 2,555 MW in 2022.

In their report on the second event, NERC and Texas RE staff pointed out that most of the solar PV sites that responded abnormally in 2022 also did so in 2021. However, the cause of reduction for most of the facilities in the 2022 report was different from that recorded the previous year; many of these had implemented changes intended to prevent the causes of reduction in 2021.

The report concluded that addressing the performance issues of solar plants and other inverter-based resources is a “paramount” priority for the ERO that also requires the assistance of stakeholders including FERC, ERCOT, and electric utilities.

Gravois reviewed the risk mitigation measures that ERCOT undertook following last year’s disturbance. The first step was to convene discussions with generator owners (GO), original equipment manufacturers (OEMs) of the inverters involved in the incident, Texas RE, and NERC to investigate the root causes of the inverter tripping.

Following these meetings, the ISO ordered the affected GOs to submit mitigation plans and timelines within three weeks for correcting the identified issues. After the utilities submitted their plans, Gravois said ERCOT “followed up with them continuously … to make sure they were meeting the timeline [and] when we can expect these corrective actions to be implemented.”

Although the utilities have only had “the better part of fall 2022” to put their mitigation plans in place, Gravois said they are “getting really close” to completion. One of the few remaining measures needed on a widespread basis is a firmware update to inverters manufactured by Toshiba Mitsubishi-Electric Industrial Systems to address the DC voltage imbalance observed at three facilities.

“They had this ready to go at the time of the Odessa 2022 event, they just hadn’t implemented it yet,” Gravois said. “So they … will be implementing this in the rest of the facilities with these inverters throughout Texas as well, [and] ERCOT’s going to be reaching out to these facilities as well to make sure they’re working … to get this implemented.”

Further activities planned by ERCOT for 2023 include requesting GOs of affected facilities to update and resubmit their dynamic models to verify that they match the equipment’s field settings. The ISO also plans to contact all facilities, whether “operational or in the commissioning phase … to make sure they’re also proactively implementing all these corrective actions we’ve identified so they don’t trip off for future events.”

ERCOT’s longer-term goals include improving the interconnection process to check for known issues during commissioning and developing automated tools to look for small trips that might be signs of larger developing issues. Gravois said there also “really needs [to be] some discussion within ERCOT to look into running some kind of systemwide validation” to make sure GOs’ updated models are accurate.

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Beacon Wind Draws Public Support at Power Line Hearing

The proposed Beacon Wind I project drew unanimous public support Tuesday during public hearings on the transmission line needed for the 1,230-MW wind farm planned off the New York coast.

The New York Public Service Commission held virtual comment sessions as part of its review process for the certificate of environmental compatibility and public need the developers must secure.

Many other state and federal approvals are needed before Equinor and BP can begin construction in 2025 in a 128,000-acre tract of ocean 60 miles east of the southeastern tip of Long Island.

Tuesday’s hearings officially centered on the 115-mile underwater export cable running the length of Long Island Sound, plus a short overland cable and substation where it will make landfall in Astoria, Queens, in the northwestern corner of Long Island.

But everyone who spoke — activists, residents with no stated affiliation, business owners, and elected, union and neighborhood leaders — was in favor not just of permitting the cable but the entire project, and offshore wind in general.

The written comments submitted to the PSC were similarly supportive.

The level of public support for zero-emission wind power in and near the Astoria neighborhood is not surprising; the area has been dubbed Asthma Alley for its concentration of fossil fuel power facilities, past and present.

A subsidiary of NRG Energy (NYSE:NRG) had initially proposed to refurbish the Astoria Generating Station, a 558-MW peaker plant, prompting vigorous protests from neighborhood and climate activists.

The state Department of Environmental Conservation rejected a plan to install a new 437-MW turbine generator on-site, saying it would not meet the emissions limits set in the Climate Leadership and Community Protection Act.

So instead, Astoria Gas Turbine Power opted to sell the site to Beacon Wind Land and demolish the power station.

Equinor told RTO Insider via email Tuesday that the purchase of part of the complex is complete, and the developers would share more of their plans for the site in coming weeks.

Among the speakers Tuesday:

  • Casey Petrashek of the New York League of Conservation Voters said: “Beacon Wind I will bring significant environmental and economic benefits to New Yorkers.”
  • Kayli Kunkel, founder of the Earth and Me ecologically themed stores in Queens, said: “Clean, renewable energy and air and water quality are rights that we deserve as New Yorkers, and considering the diverse makeup of our borough, this is also an environmental and racial justice issue.”
  • Edwin Hill Jr., of the International Brotherhood of Electrical Workers, said the union appreciates Equinor’s commitment to organized labor on the project. “Equinor has made a significant commitment of $52 million in social investments in New York state,” he added.
  • Fred Zalcman, director of the New York Offshore Wind Alliance, urged the PSC to grant the certificate of compliance and need. “The Beacon Wind project is a critical component of New York’s nation-leading effort to power its economy based entirely on clean, renewable and carbon-free energy resources.”
  • Marc Schmied, a volunteer with 350Brooklyn.org, contrasted the impact of constructing offshore wind farms with that of continued reliance on fossil fuel. “I understand and respect the concerns of both the local residents and the commercial fishermen who will be temporarily inconvenienced by the construction of Beacon Wind’s transmission line,” he said. “Offshore wind is by far the lesser of two evils here.”
  • State Assemblyman Zohran Mamdani, a Democrat who represents Astoria, said: “Our neighborhood has been on the front lines of the climate crisis but also on the front lines of fighting back, and last year we successfully beat back NRG’s proposal to build a fracked gas power plant, and the approval of this permit will ensure that very same site that the plant would have been built will instead become an interconnection site.”
  • Richard Khuzami, representing the Old Astoria Neighborhood Association, said: “The Astoria waterfront, home to three major [public housing complexes] has long been afflicted by increased rates of asthma and other environmentally related afflictions, and this project will have a direct positive impact and improve quality of life.”

Innovation Hub

As the developers push through the regulatory process, they are also taking steps to set up a supply chain, with construction of a tower manufacturing facility on the Hudson River in upstate New York and construction/support hub on the New York City waterfront.

Equinor and several partners on Tuesday announced the opening of the Offshore Wind Innovation Hub in Brooklyn, which will help startups develop innovation in the offshore wind industry.

In a news release Tuesday, Lyndie Hice-Dunton, executive director of the National Offshore Wind Research and Development Consortium, said:

“We are delighted to be a part of this exciting partnership. The Accelerator Program is a unique opportunity to help support innovative solutions for offshore wind in the U.S., as well as help build strategic partnerships within this growing industry. We are looking forward to working with this outstanding group of leaders to achieve our mutual goal of accelerating offshore wind innovation.”

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Dominion-backed Bill Promises Savings, but Comes with Strings

Dominion Energy is backing legislation in Virginia that critics say would limit the State Corporation Commission’s ability to set its rates, while the utility has claimed it would save consumers millions.

Senate Bill 1265 also initially included language that would have made energy shopping by large commercial and industrial customers “nearly impossible,” according to the Retail Energy Supply Association, but that was removed as it advanced through a Senate subcommittee last week.

“As Virginians face historic inflation and rising energy costs, there is broad agreement that consumers need relief on their power bills,” a Dominion spokesperson said. “The proposed legislation would provide immediate and ongoing rate relief to our customers. It would provide strong state regulatory oversight. And it supports our mission of delivering reliable, safe, affordable and clean energy to our customers.”

The bill, sponsored by Sen. Richard L. Saslaw (D), cleared the Energy Subcommittee by a 4-1 vote, and it still must clear the full Commerce and Labor Committee before it can be voted on by the Senate. A House version of the legislation, HB 1770, has not moved forward yet.

Ever since Virginia decided against moving forward with retail restructuring back in 2007, state law has required the SCC to set Dominion’s rates based on a group of its investor-owned peers in the Southeast.

The bill would eliminate the SCC’s ability to remove the two highest returns on equity and two lowest returns from that peer group when setting Dominion’s rates. In return for that, it would shift some costs from riders to the firm’s base rates and make it go through rate cases every two years instead of every three.

Eliminating those riders would save $300 million annually effective July 1, which would save the average customer bill about $5 to $7 per month.

While the bill removed any language dealing with electric shoppers, at a Senate Energy Subcommittee hearing last week lawmakers indicated that they want to hear from the SCC on whether shopping shifts costs to remaining customers. That is an issue in California’s capped power market, where cost shifts from customers leaving utility service are covered through a mechanism called the power charge indifference adjustment.

“Our rates have been below the national average for some time,” Dominion Senior Vice President of Corporate Affairs Bill Murray said at last week’s subcommittee hearing. “This is a way for us to keep our rates below the national average, while having the certainty we need to raise a great deal of capital to build needed infrastructure, whether its generation, transmission or grid-hardening.”

The current peer group on which Dominion’s rates are based is made up of about 10 utilities in the Southeast, and Dominion has the lowest rate of return on equity among them, Murray said. That peer group has shrunk from about 20 when the legislature first set it up 15 years ago because of industry consolidation, so removing two highest returns and two lowest has a much bigger impact on Dominion’s rates than it usSBed to.

If Dominion wanted to offer customers $300 million in savings, the firm could do so on its own without any legislation, Southern Environmental Law Center’s Will Cleveland said at the hearing.

“This legislation does not let the Virginia commission set the rate of return for the Virginia monopoly utilities — that is our concern,” Cleveland said.

Walmart lobbyist Kenneth Hutcheson told the subcommittee the retailer appreciated the removal of changes to the state’s shopping rules, but he said the peer group should be expanded to include vertically integrated utilities from the Midwest and Gulf Coast.

Attorney Will Reisinger testified at the hearing on behalf of Clean Virginia, saying it would remove the ability of the SCC to independently set Dominion’s rates.

Eventually all the investments Dominion is making, including projects to meet the goals of the Virginia Clean Economy Act such as the 2.6-GW Coastal Virginia Offshore Wind project, would be impacted by any higher rates of return Dominion is able to get under the legislation, Reisinger said in an interview.

“It’s pretty extraordinary for a monopoly utility to try to set its own rate of return via legislation,” Reisinger told RTO Insider. “This is exactly what public utility commissions were designed to do — set the utility’s ROE at the correct level.”

The Dominion-backed legislation isn’t the only bill under consideration.

Senate Bill 1321, sponsored by Sen. Jennifer McClellan (D) and Sen. Creigh Deeds (D), and House Bill 1604, sponsored by Del. R. Lee Ware (R), would allow the SCC to lower a utility’s base rates if it finds they result in “unreasonable revenues in excess of the utility’s authorized rate of return.” The bill has also been assigned to the Senate subcommittee.

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Generators Oppose PJM Filing to Change Capacity Auction Parameters

Generation owners are attacking PJM’s filing asking FERC to approve a change to the parameters of the RTO’s 2024/25 capacity auction, calling it a tariff violation and an attempt to intervene on behalf of buyers.

But utilities and state advocates argue that the potential impact of the auction’s results on ratepayers justifies the action.

In two filings last month, PJM laid out how a mismatch between the resources used to calculate the reliability requirement for the DPL South (DPL-S) locational deliverability area (LDA) — centered on the Delmarva Peninsula — and those that actually participated in the auction led to a fourfold increase in clearing prices compared with the previous year’s auction (EL23-19, ER23-729).

Describing the outcome as an artificial inflation in prices, the filings asked the commission to allow PJM to revise the reliability requirement to remove those generators that did not enter the auction as an additional step in the optimization algorithm run after bids have closed. (See PJM Decides Against Posting Indicative Capacity Auction Results.)

The core argument of the generators’ protests is that PJM’s tariff requires it to close the auction and post the results as soon as possible and that the RTO lacks the authority to hold it open while making a filing with FERC.

Former FERC Chair Joseph Kelliher submitted an affidavit in support of the PJM Power Providers (P3) protest to PJM’s filing, saying that granting the RTO’s request would violate the filed rate doctrine, which prohibits the charging of rates different from those filed with FERC, and the rule against retroactive ratemaking.

In rebutting PJM’s argument that changing the auction parameters would not violate the rules because the auction has not been completed, Kelliher compared the auction results to Schrodinger’s Cat. He noted that the RTO has stated that the results are preliminary and incomplete, but relies on the figures to estimate the impact to clearing prices in DPL-S.

“[T]he auction process appears to be final, except for the ministerial step of posting the auction results that PJM apparently has in hand but refuses to formally post — are the auction results final or preliminary?” he wrote.

Kelliher also argued that granting PJM’s requests would be bad policy, undermining confidence in capacity auctions and the commission.

“The commission has consistently recognized the importance of assuring market certainty and maintaining market integrity, even to the extent of opposing the re-running [of] RTO auctions to provide refunds as remedies in FPA Section 206 complaint proceedings and in response to court remands, where [the] commission has discretion to order re-running of markets, on the grounds that doing so would ‘undermine confidence in markets,’” he said.

NRG Argues Price Jump was Predictable Months Before Auction

In its protest, NRG Energy said it had relied on the market information and price estimates based on them to make “irreversible commercial decisions.”

“In its determination to retroactively revise the auction results to avoid politically unpalatable results dictated by the rules in effect when the auction was conducted, PJM blithely ignores the substantial and actual reliance interests of the NRG Companies and other market participants and proposes to change the rules after-the-fact,” the company wrote.

It also argued that PJM should have been aware of the likelihood that the reliability requirement would lead to elevated prices in DPL-S, as the company had previously reached out to PJM to inquire about the 12% increase for the LDA. The RTO responded that historical winter forced outages and expected increase in solar resources increased the risk of loss of load in the winter, leading to the higher reliability requirement.

Based on those parameters, the company estimated that the LDA would clear at around the cap of $426.17 MW/day and instructed traders to rely on PJM’s parameters after receiving its response, leading the company to reject capacity purchase offers on the grounds that it expected higher prices.

EPSA Worries About Reliability Impacts

The Electric Power Supply Association (EPSA) noted that the reliability requirement for LDAs looks at existing resources and projected resources expected to be in service, rather than at resources with Reliability Pricing Model (RPM) commitments. For that reason, EPSA contended, revising the reliability requirement to exclude resources not offered into the Base Residual Auction (BRA) would create a “false equivalence between the reliability needs of an LDA and the supply and demand in the LDA in an RPM auction.”

Drawing on information in an affidavit by Paul Sotkiewicz, president of E-Cubed Policy Associates, EPSA argued the effect would be dramatic differences in clearing prices depending on whether resources participated in auctions, regardless of whether those resources are actually available during the delivery year.

“The prices PJM would determine might not be high enough to attract future new resources to take on an RPM commitment especially knowing PJM is willing to put its finger on the scale to reduce prices even in the face of reliability needs with its proposal,” Sotkiewicz wrote.

AMP, Public Citizen Argue PJM Doesn’t Go Far Enough

American Municipal Power argued that FERC approval of PJM’s filing is necessary to avoid ratepayers paying a “Locational Reliability Charge that is unjust, unreasonable and unduly discriminatory.” The nonprofit, whose members include the Delaware Municipal Electric Corporation, said the RTO’s solution could leave future BRAs open to similar issues and called on FERC to establish a technical conference to explore long-term solutions.

In particular, AMP argued that the small size of many LDAs within PJM can cause price volatility through changes in load forecasts, uneven growth in resource development and generators not participating in auctions.

“It is therefore critical that LDAs in PJM be sized large enough that the failure of one resource or a small set of resources to participate in RPM auctions, or the inability to site new generation, does not drastically increase the auction clearing price,” AMP wrote.

The nonprofit power supplier also questioned PJM’s proposal to trigger the process of recalculating the reliability requirement to remove resources not participating in the BRA when the parameter increases more than 1% over the previous year. It noted that a 400% increase in clearing prices could be attributed to the 12% increase in the requirement. A 1% increase in the threshold would still correspond with a 33% rise in prices should the impact prove to be linear, AMP said.

Public Citizen argued that FERC should approve PJM’s requests, establish a refund date and investigate whether market participants engaged in intentional capacity withholding. It also wrote that future BRA results should be filed as standalone Section 205 rate filings to allow for public inspection of rates with the ability for comments and protests to be submitted before rates go into effect.

“Setting the matter for hearing and subjecting the capacity auction to refunds is the statutorily appropriate path for the commission to pursue, rather than PJM’s proposed ‘do over’ which does not appear to be permitted by its tariff. Subjecting the auction results to a hearing with refund authority will protect consumers and ensure accountability for any generators that engaged in capacity withholding,” the organization wrote.

Delmarva Zone Parties, ODEC Support PJM Approach

In its comments supporting PJM’s filings, Old Dominion Electric Cooperative said that actions being proposed are justified given the “artificially increased and unreasonable clearing price” that ratepayers would pay without any added benefits from the higher costs.

“The fact that prices are being increased and LSEs (and, thereby, consumers) will pay for an inappropriately calculated Reliability Requirement is in and of itself sufficient basis for the commission to take action to prevent the imposition of unjust and unreasonable capacity prices for the DPL-S LDA. When there are no discernable benefits from increased prices, the rates cannot possibly satisfy the requirement that customers receive benefits that are at least roughly commensurate with costs,” the cooperative wrote.

Several Delaware, Maryland and Virginia public organizations also supported PJM’s filings and said whatever solution FERC may approve, priority should be given to ensure that further delays in the BRA are avoided. Jointly filed by the Delmarva Zone Parties, the comment was signed by the Delaware Public Service Commission, Delaware Division of the Public Advocate, the Delaware Municipal Electric Corporation, Maryland Public Service Commission and the Virginia State Corporation Commission.

“Avoiding further delays in the BRA timeline is particularly critical as PJM stakeholders seek to reestablish the three-year forward procurement of capacity resources that has already been delayed by various proceedings before the Commission. Instead, in an effort to minimize disruption to the BRA process, PJM proposes to prospectively include a new element to its optimization algorithm that would allow it to reflect more accurately supply and demand levels while evaluating Sell Offers before determining capacity awards,” the parties wrote.