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November 13, 2024

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OSW Transmission Planning Must be Interregional, Networked and Start Now

The U.S. will require a massive mobilization of resources and unprecedented collaboration among federal, state and regulatory authorities to build the transmission needed to the meet its aggressive offshore wind goals, a new report says.

Those goals include President Biden’s call for 30 GW of offshore wind by 2030 and a national target of 110 GW by 2050.

Such “proactive and holistic” planning efforts could save U.S. consumers $20 billion and reduce environmental and community impacts by 50%, according to the report, “The Benefit and Urgency of Planned Offshore Transmission,” compiled by The Brattle Group for a consortium of clean energy and grid advocates.

“Compared to the current process of developing and interconnecting one OSW generation project at time, each with its own cables to shore, a coordinated comprehensive transmission plan could unlock numerous efficiencies and benefits unavailable under current processes,” the report says.

But “to achieve these benefits, state and federal policymakers, industry regulators, system operators and market participants must expeditiously address” existing obstacles, such as interconnection and permitting reform, the report says. “Even modest delays in developing and implementing actionable plans for both near- and long-term transmission investments substantially reduces [sic] the benefits of such planning efforts.”

For example, the report cites a study done by National Grid in the United Kingdom finding that a delay of five years in long-term transmission planning would cut benefits — including $7.4 billion in costs savings — in half.

“If we don’t carefully plan, it’s not just the next 10 to 15 years,” said Johannes Pfeifenberger, a principal at The Brattle Group and lead author of the report, speaking at a launch webinar on Tuesday. “But with a view to 2040 and 2050, we are really prone to severely limit our future options.”

The report’s to-do list is daunting. In the next year alone, federal and state governments must increase funding and staff for offshore transmission planning, and the Internal Revenue Service must clarify the offshore wind tax credits in the Inflation Reduction Act. Offshore developers are specifically looking for the IRS to confirm that a project’s transmission infrastructure will qualify for the tax credit.

At the same time, states will have to come together to form multistate “transmission authorities,” which will “facilitate the planning and procuring of effective regional and interregional transmission solutions,” the report says. Federal leasing processes should be changed to lay out “offshore cable routes between projects,” and “network ready” standards for offshore substations and cables must be developed to ensure interoperability between projects.

A range of funding opportunities and incentives in the IRA and Infrastructure Investment and Jobs Act should be leveraged to jump-start these and other mid- and long-term recommendations in the report. Potential funding sources in the IRA include $760 million to help with siting of interstate and offshore transmission and $2 billion in financing, such as loan guarantees, for transmission projects the Department of Energy designates as being “in the national interest,” the report says.

But, Pfeifenberger said, some IRA funds, such as offshore wind tax credits, sunset in 10 years, which is about how long it takes to permit and build an offshore project and transmission; hence, the need for immediate action. “We won’t be able to take advantage of [IRA funding] unless we start to plan for what it is that we need,” he said.

A Burning Fuse

A joint project of the Natural Resources Defense Council, GridLab, the Clean Air Task Force, the American Clean Power Association and the American Council on Renewable Energy, the report’s call for urgency is rooted in the confluence of the expansion of offshore wind in the U.S. and the federal funding opportunities in the IRA and the IIJA.

In addition to Biden’s 30 GW, states on both the East and West coasts have set offshore targets totaling 77 GW by 2045, and a range of studies are projecting the U.S. could need as much as 460 GW of offshore wind to meet its 2050 climate goals, the report says.

Connecting these projects to the onshore grid requires laying underwater cable and finding onshore points of interconnection (POIs) that may run across beaches or through coastal communities, as well as interregional high-voltage DC transmission lines to get power to load centers. Projects and their transmission can take a decade to site, permit and build, making the need for forward planning more urgent, as does the siting of multiple projects near each other, as is now occurring on the East Coast, the report says.

“The days of low-hanging fruit where you have near ready-made POIs are really done, and we’re starting to brush up against some really tough nuts to crack in terms of interconnecting these resources,” said Robert Golden, senior adviser for clean energy infrastructure at the White House. “The opportunity is huge to deliver for customers, but this is really a bit of a burning fuse, and if we don’t move quickly a lot of the benefits … can vanish off the table.”

“Current interconnection points are not sufficient to accommodate all the offshore wind that is expected to come online over time,” agreed Lopa Parikh, head of electricity policy for offshore wind developer Ørsted, which is currently working on eight projects off the Atlantic coast. “So, any proposals for transmission projects that are considered really need to consider the full scope of potential offshore wind development to ensure that they can be accommodated over the long run. … This is especially true since most of the offshore wind is currently being developed close to load centers, which greatly increases the need to create more efficient transmission planning.”

The benefits of such coordinated planning could include a 60% to 70% reduction in the need to upgrade onshore transmission lines or run lines across beaches or through coastal communities. The amount of underwater cable needed for projects could also be cut by as much as 2,000 miles, the report says.

“Every time you have to go back and disturb [an] area, that impacts the communities,” said Suzanne Glatz, director of strategic initiatives and regional planning at PJM. “There’s a lot of value to be extended if we can minimize the number of times we have to go back to those areas.”

Suedeen Kelly, a former FERC commissioner and now a partner at law firm Jenner and Block, believes that offshore wind development should be seen as a “unique effort in America. … We shouldn’t necessarily try and pigeonhole this planning process into existing frameworks and existing silos.”

“We don’t really know what the best configuration of an offshore grid is,” Pfeifenberger said. “Is it just meshed radial lines? Is it a backbone? Is it some sort of combination of these things? We need a planning process to figure out what is the best configuration for a given region.”

At the same time, Pfeifenberger sees interregional offshore transmission planning as providing new opportunities for improving grid reliability and resilience. “We can use the offshore infrastructure to reinforce the onshore grid, and there is a lot of interregional transmission that studies find would reduce total costs faced by consumers significantly, and offshore links may be the most cost-effective way to provide that regional and interregional transfer capability.”

He also envisioned “multipurpose connectors … that not only bring offshore wind to shore but also create reinforcement to the onshore grid,” he said. The problem, however, is that the HVDC lines that would be used in such networks have a higher capacity than the standard maximum most RTOs and ISOs can handle, even in a “most severe single contingency,” Pfeifenberger said.

“That kind of [HVDC] network would really improve the reliability of delivering offshore wind. It allows for higher capacity transmission cables that are … able to reroute power and avoid large impacts on individual grid nodes,” he said.

Switching Trains

The report’s call for urgent action on transmission planning for offshore wind comes at a time when FERC and RTOs/ISOs are all wrestling with planning and interconnection issues, though their focus has been regional, rather than the interregional coordination the report sees as critical. In addition, Pfeifenberger said, these bodies will also need to work on new frameworks for regulations, contracts and markets.

Brattle has done a number of studies advocating for coordinated planning for offshore wind for New York and New England, comparing the cost and impacts of traditional, siloed planning with a holistic, networked approach in which multiple projects can be linked or can share cables and POIs.

“Before we have a networked offshore grid, we will need the regulatory and contractual framework for shared network operations,” he said. “The regional grid operators need to tune up their operations and market design because right now they are not ready to handle HVDC links, either within their region or across regions,” he said.

FERC’s anticipated rulemaking on regional transmission planning “will be very helpful, at least if the final rulemaking is anything like the [Notice of Proposed Rulemaking] itself,” Pfeifenberger said. “However, FERC rulemaking won’t be effective unless there is also leadership from the regional grid operators and the states.”

The lack of collaboration between states and grid operators was one of the factors behind the failure of FERC Order 1000, the grid planning order the commission issued in 2011, he said.

“We’re basically trying to develop a process that allows us to switch trains while both trains are moving at high speed from the current process to a better planning process, and that requires a lot of additional thought and preparation,” Pfeifenberger said.

Not yet finalized, the NOPR would direct transmission providers to revise their planning processes to, among other things, identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs. It has had a mixed reception among industry stakeholders. (See Battle Lines Drawn on FERC Tx Planning NOPR.)

Following the departure of Richard Glick as FERC chair, the commission is now potentially deadlocked with two Democratic and two Republican commissioners, leaving the future of the rulemaking uncertain.

Kelly sees the regional NOPR as a first step but stressed that it will not cover the kind of interregional planning needed for offshore wind. FERC could, she said, “play a pivotal role initially by becoming a national forum for the provision of information prior to talking about any kind of regulation.”

By hosting a series of technical conferences, FERC could provide “a single place where interested developers, states [and other] stakeholders could come” to discuss the issues, she said.

Equal Access Is Key

But developing any new transmission planning processes must not slow down or delay projects already underway, Parikh said. “Making changes to projects that have already been awarded could negatively impact the viability of these projects and the ability for them to interconnect in a timely manner.”

PJM’s state agreement approach (SAA) with New Jersey is one way forward, Glatz said. Under the SAA, PJM ran a solicitation for the New Jersey Board of Public Utilities for transmission projects to connect 6,400 MW of approved offshore wind projects to the grid. According to the report, the solicitation and the resulting projects chosen by the BPU saved the state $900 million. (See NJ BPU Oks $1.07B Transmission Expansion.)

She also pointed to PJM’s interconnection reforms, recently approved by FERC, that will shift the RTO from its current first-come, first-served methodology to instead studying new service requests with a first-ready, first-served approach that clusters proposed projects together to determine network impacts and allocate network upgrade costs. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

The reforms mean “we can be looking out to not only the first project, what it would take to interconnect that one, but also the one after and the one that comes two or three years after that,” Glatz said. “What is that holistic solution to meet the interconnection of those projects?”

But forward planning also carries certain risks. “You are planning for multiple projects, some of which may not be very far along or even yet entered into the interconnection queue,” she said. “So, there’s a possibility that those will not materialize, and you may have more transmission built that could be more costly.”

Glatz also stressed the independent role RTOs play as “organizations that plan the system to meet the needs of all system users, which would mean studying all generation requests in a nondiscriminatory manner and to provide equal access to all of them.”

The RTOs’ wholesale markets must also provide equal, nondiscriminatory access, Glatz said. “Assuring that the planning process still serves that purpose is really key to anything we’re going to consider in terms of potentially prioritizing any resources.”

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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.