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November 16, 2024

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Texas PUC Approves ERCOT Board’s 83.9% Pay Increase

The Texas Public Utility Commission on Thursday unanimously approved ERCOT’s request to nearly double compensation for its independent directors, the board’s first increase since 2012.

The order increases the eight directors’ annual compensation from $87,000 to $160,000, an 83.9% increase. It also raises the supplementary compensation for the board chair from $12,800 to $35,000 and from $7,500 to $15,000 for the vice chair. Committee chairs also will now receive an additional $25,000, up from $5,600. (54444).

“There have been a lot of changes and a lot has happened at ERCOT over the last decade and we should compensate appropriately,” PUC interim Chair Kathleen Jackson said during the open meeting.

Commissioner Will McAdams noted that until 2021 legislation removed market participant representatives from the board in favor of independent directors, ERCOT was able to compensate its board at lower levels. Under the new rules, the grid operator’s directors are required not to have fiduciary duty or assets in the ISO’s market and must divest themselves of energy-related investments.

“That makes this a fairly restrictive framework around finding qualified people who can serve,” McAdams said. “In principle, I want a system managed by individuals who can dedicate the time and focus to a grid that is in the midst of [a] most significant energy transition. I believe this will allow us to recruit and retain a dedicated governing body for the system, independent of the industry, which was the legislature’s intent and to be able to execute the reforms that we are required to implement along the timetables that we are required to implement them by.”

Commissioner Jimmy Glotfelty said he struggled with compensation increases for grid operator executives and their board members, saying comparing their salaries to those of publicly traded companies is not a “correct comparison.”

“We have to protect ratepayers … I just hope that in time, we set this and we leave it. We can’t let this be a spiraling issue where costs go unchecked for the consumers of this state,” he said before voting in favor of the increase.

Commissioners Lori Cobos and Peter Lake were both absent from the meeting for personal reasons. Lake’s term expired Friday.

The ERCOT board and its Human Resources and Governance (HR&G) Committee both approved the increase in June following its annual review of director compensation.

The board hired executive compensation consulting firm Meridian Compensation Partners to perform a benchmarking analysis that analyzed compensation at other ISOs and RTOs, comparably sized general industry companies, ERCOT market participants and other public companies.

ERCOT said the firm consulted with HR&G in making its recommendation, which was based on considerations that included the directors’ high volume and complexity of work, recruitment considerations and external optics and standards.

The compensation became effective July 1.

The ISO’s eight independent directors are appointed by the state’s three-person ERCOT Board Selection Committee, which is comprised of appointees from the governor, lieutenant governor and the Texas House of Representatives’ speaker.

The board’s non-voting ex officio members — the ERCOT CEO, PUC chair and the Office of Public Utility Counsel’s CEO — are not covered by the order.

Recent legislation will increase the board to 12 members in September when a second PUC commissioner becomes an ex officio member.

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ERCOT Technical Advisory Committee Briefs: June 27, 2023

ERCOT staff said last week­ that it faces a tight timeline to add a new ancillary service by Dec. 1, 2024, as required by a recently enacted Texas law.

Texas lawmakers passed a sunset bill (House Bill 1500) that includes a directive to ERCOT to develop an uncertainty product called dispatchable reliability reserve service (DRRS). Based on historical variations in availability for each season, the DRRS’ criteria require participants to be online and dispatchable for less than two hours after being deployed and to run for at least four hours at their high sustained limit.

Kenan Ögelman, ERCOT vice president of commercial operations, told the Technical Advisory Committee on June 27 that staff are still working through its options, but that the date is “very, very limiting in terms of what we can do.”

“The only real chance we have to meet that statutory deadline is to use an existing service, but we are hopeful that maybe stakeholders will have some brilliant idea that we didn’t think of,” Ögelman said.

The DRRS’ objective is to reduce ERCOT’s reliance on reliability unit commitments (RUCs), which have soared under the grid operator’s conservative operations posture during the last two years. The legislation requires that RUCs be reduced by the amount of DRRS that is procured and that the product be provided by offline resources.

ERCOT’s Kenan Ögelman explains the obstacles facing the new ancillary service. | ERCOT

Because ERCOT also uses RUCs for local reliability needs, as required by NERC, Ögelman said RUC reductions can only be achieved when they are not needed to cover load and reserve obligations. He also warned that DRRS’ deployment will have implications on prices as its reliance on offline resources means there will be less energy available for dispatch.

“I do think there are going to be things that impact both forward positions and contracts and so forth,” Ögelman said.

Given the time constraints, members discussed repurposing other ancillary services, including its first new product in more than 20 years, ERCOT contingency reserve service (ECRS), as well as non-spin reserve service. ECRS provides the system with additional capacity that can ramp in 10 minutes to respond to short-term net load ramps, and non-spin offers capacity that can be available in 30 minutes to cover forecast errors or to replace deployed reserves. (See “New Ancillary Service Deployed,” ERCOT Board of Directors Briefs: June 19-20, 2023.)

Carrie Bivens, who leads ERCOT’s Independent Market Monitor, said she was “disheartened” by the discussion of procuring more ECRS and called for a holistic review of ancillary services.

“I like the idea of repurposing non-spin … so adding more is going to have unintended consequences,” she said. “A big portion of the non-spin that gets procured is for six-hour load-forecast uncertainty, and I don’t know why you need a 10-minute online product to handle that. I think we have too many megawatts behind the house right now.”

Staff plan to schedule workshops in July to solicit broader stakeholder input and continue to evaluate the pros and cons of other alternatives. Discussions with the Public Utility Commission and stakeholders will continue into August, when staff will also begin to develop the protocols. Ögelman said he hopes to bring a recommendation to the Board of Directors in October and secure the PUC’s approval in November, giving staff a year to translate the protocols into requirements, develop the software and deploy the product.

“None of this is set in stone,” Ögelman said.

Eric Goff, who represents residential consumers, said the uncertainty over the ancillary services market makes it difficult for retailers to determine their charges to consumers.

“The sooner we can resolve this, the better,” he said. “The uncertainty could cause problems. This also ties into the importance of the ancillary services methodology.”

Real-time Co-optimization Is Back

ERCOT’s Matt Mereness told the committee that staff will “blow the dust off everything” in resuming work this week on the real-time co-optimization (RTC) project.

The market mechanism would expand ERCOT’s real-time market by clearing energy and ancillary services every five minutes, as most other grid operators already do. However, it has been on hold since the February 2021 winter storm. ERCOT leadership has said RTC’s reliability benefits in addressing future operational challenges make the tool a strategic priority.

“The key delivery areas that we have is heads down on [writing] the business requirements [and] getting the band back together,” Mereness said. “We’re off and running with this program.”

Staff and market participants drafted and received approval for eight nodal protocol revision requests (NPRRs) related to RTC before the project was halted. However, a battery task force was unable to complete its work on state-of-charge modeling when dispatching batteries. With batteries expected to be capable of providing 14 GW of energy by 2025 and RTC touching almost every major system, Mereness said, staff and stakeholders will also have to address battery functionality as part of the project’s effort.

An updated ERCOT impact analysis has reduced the project’s costs down to about $50 million to deploy in 2026, thanks to some hardware savings and “right-sizing” some of staff’s efforts.

The RTC’s development will begin in April 2024, Mereness said, with the primary risk being maintaining staff availability without interruption during the 3.5-year effort.

“We know this is a squeeze play,” he said. “RTC doesn’t come in and take over everything; it has to fit in with everything else. But the executive team said, ‘Let’s do this and keep the foot on the pedal where we can to keep this thing moving forward.’”

7 Revision Requests Pass

TAC unanimously approved a combination ballot that included two NPRRs, two revisions to the nodal operating guide (NOGRRs), an other binding document request (OBDRR), and single changes to the load-profiling (LPGRR) and planning guides (PGRR). If approved by the board, these changes would:

    • NPRR1150: require qualified scheduling entities (QSEs) that represent resource entities, emergency response service resources or other QSEs, and that receive or transmit wide area network (WAN) data to maintain connections to the ERCOT WAN and a secure private network.
    • NPRR1163 and LPGRR070: discontinue the process of evaluating interval data recorder meters to determine whether any are weather-sensitive.
    • NOGRR230: ensure the WAN data transmission’s integrity by requiring data be shared in a manner that prevents denial of service and distributed denial-of-service attacks.
    • NOGRR251: add cold weather conditions to the template used for developing emergency operations plans to align with NERC Reliability Standard EOP-011-2 (Emergency Preparedness and Operations).
    • OBDRR045: edit the demand response data definitions and technical specifications, including modifications to the electric service identifiers list provided to retail electric providers.
    • PGRR103: require interconnecting entities to complete all conditions for commercial operation of a generation resource or energy storage resource within 180 days of receiving ERCOT’s approval for initial synchronization.
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FERC Issues Order 898, Changing Its Uniform System of Accounts

FERC on Thursday issued Order 898, its final rule updating its Uniform System of Accounts (USofA) to account for rapid changes in technology and the resource mix in the power industry (RM21-11).

The changes adopted in the final rule will add functional detail to the USofA to provide uniformity, consistency and transparency in accounting and reporting for investments in renewables and other newer technologies.

The rule creates new subfunctions and accounts for wind, solar and other renewable generating assets. It establishes a new functional class and accounts for energy storage assets. It also creates new accounts and codifies accounting treatment for environmental credits and creates new accounts for computer hardware, software and communication equipment within existing functions that do not already include them.

The new rules also created new accounts and codified the accounting treatment of renewable energy credits.

“By adding functional detail to the USofA, these reforms will provide uniformity, consistency and transparency in accounting and reporting for investments into these assets and assist the commission in fulfilling its responsibilities under the FPA to ensure that rates remain just and reasonable,” the order said.

Given the rapid expansion and development of renewable generation, FERC concluded that its accounting system must be changed to better deal with the technologies.

FERC first proposed the changes in a Notice of Proposed Rulemaking last year and said it largely adopted the proposal with some changes to better reflect its intent, to address the needs of stakeholders and to facilitate solutions to potential technical challenges. (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.)

The USofA goes back to when FERC was called the Federal Power Commission and was meant to facilitate its ratemaking responsibilities and uniformly capture financial and operational information for utilities, and then natural gas pipelines. It has been updated previously to reflect changes in the industry and law, including after the 1990 Clean Air Amendments to account for its creation of sulfur dioxide emissions allowances.

It was also updated 10 years ago in Order 784, which dealt with energy storage technologies, but those changes underestimated the additional burden that functional reporting, along with frequent reclassification of plant assets and associated depreciation, imposes on utilities. The new rules around storage are meant to simplify and improve the recording and reporting of energy storage assets and related expenses.

The USofA already included discrete production accounts for steam, nuclear, hydraulic and other resources, but it did not contain accounts designated for solar, wind or other nonhydro renewable generating assets. Regulated firms used to put their renewable generation in the “other production” accounts, and FERC noted before it issued the NOPR that parties disagreed on whether new accounts would be useful.

But none of the old categories clearly described solar panels, photovoltaic inverters, wind generation towers, or the computer hardware and software required to operate such generators. Related operations and maintenance accounts also failed to uniquely accommodate costs to maintain wind and solar facilities.

The USofA also did not explicitly address the purchase, generation or use of RECs, which are similar to the sulfur dioxide emission allowances from the Clean Air Act and previously were included in those accounts.

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FERC Denies Rehearing over SPP Z2 Credits

FERC last week rejected four separate rehearing requests related to SPP’s revenue credits under Attachment Z of its tariff, reaching the same conclusion it did in a November order last year while also offering clarifications.

Oklahoma Gas & Electric (EL19-77), Western Farmers Electric Cooperative (EL19-93), Cimarron Windpower (EL19-96) and four renewable developers (EL19-75) asked for a rehearing of FERC’s previous ruling. The commission’s order partially granted complaints over SPP’s revenue-crediting process but rejected OG&E’s complaint. (See FERC Partially Grants Z2 Protests Against SPP.)

Citing the 2020 Allegheny Defense Project v. FERC decision that ruled the commission could no longer grant rehearing requests “for the limited purpose of further consideration,” FERC on Tuesday denied each of the requests “by operation of law.”

The commission modified its discussion in the OG&E docket and set the order aside, in part. The utility had argued that requiring it to refund revenue credits related to the use of its transmission facilities would violate Attachment Z2 and a sponsored upgrade agreement with SPP dating back to 2008.

Under Attachment Z2, SPP transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrades. SPP had been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)

FERC agreed with OG&E’s contention that SPP had violated Attachment Z2 during the historical period and that the commission erred in finding the utility had not raised this argument. It also found that, consistent with its findings in the other three proceedings, SPP violated the attachments, sponsored upgrade agreement and the filed rate doctrine.

The commission said even if SPP acted in good faith in implementing and administering Attachment Z2, the tariff violation may result in an outcome that is unjust and unreasonable and/or unduly discriminatory or preferential. It granted OG&E’s complaint in part “insofar as OG&E alleged” the violations.

However, FERC again denied OG&E’s requested remedy — that SPP refund Z2 revenue credits. It said the grid operator lacked revenue credits to provide as restitution and that those funds lie instead with the transmission customers that SPP’s tariff “excuses from credit payment obligations.”

BHE Renewables, Marshall Wind Energy and Grand Prairie Wind filed a limited request for clarification or a rehearing. The commission responded by explaining that it granted several parties’ late motions to intervene in the dockets, although it did not list them. It said it granted their interventions “given their interest … as demonstrated in their motions to intervene and the absence of undue prejudice or delay.”

“Because we grant intervenors’ request for clarification, we dismiss as moot their alternative request for rehearing,” FERC said.

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Battery Storage Developers Bump Against Perception of Risk

A key piece of the puzzle in New York’s energy transition continues to have a major image problem.

A public hearing last week for a 110-MW battery energy storage facility proposed in an eastern suburb of New York City was dominated by nearby residents expressing their fears of fire and explosion.

Misused and substandard lithium-ion bike batteries and chargers are wreaking havoc in New York City. The city Fire Department reports 113 battery fires so far this year, with 13 people killed and 71 injured as a result.

These e-mobility batteries are worlds apart from the regulated and tested systems used in Li-ion BESS projects. But that distinction is seldom made, or necessary, in fire coverage produced by consumer-oriented news media. So, portions of the population do not know the differences between BESS and e-mobility batteries, or they dismiss those differences as irrelevant once they see the word “lithium.”

Bridging this knowledge gap and addressing misconceptions is becoming an important part of developing BESS projects.

Energy storage on a mass scale will be indispensable if the power grid is to be dominated by intermittent wind and solar generation in the next decade, as New York’s leaders plan.

In time, other forms of storage are expected to become technologically and economically viable. But in 2023, the storage buildout is mostly batteries, and most of the batteries being deployed are Li-ion.

NIMBY

The greater good of climate protection may coax grudging acceptance out of people opposed to the aesthetics of solar arrays and wind turbines in their neighborhoods, but fears of explosion and toxic smoke are harder to overcome. In this respect, Thursday’s Department of Public Service hearing on the 110 MW facility proposed by Savion Energy in the Long Island hamlet of Holtsville had exquisitely bad timing:

To the east, a 5-MW BESS in East Hampton had caught fire a month earlier.

To the west, a fire in a Manhattan e-bike shop had killed four people the week before.

And to the northwest, part of a 12-MW BESS system in Warwick was still smoldering, three days after catching fire. A television reporter on the ground for a standup had to leave due to an overpowering odor described as burning glue, but aerial footage showed flames through the roof of one of the BESS containers.

One Holtsville resident spoke Thursday in favor of the project, adding that he was installing a Li-ion system in his home.

But all the other speakers were adamantly opposed, citing Warwick, East Hampton, burning glue smells, blast radii, flames too hot to extinguish, explosive force equivalent to tons of dynamite, unproven new technology and lack of public outreach.

And then the inevitable words, spoken many times and in many ways before: “This maybe is not necessarily a bad thing, but this is a bad location for it … it is not something that we want in our back yards.”

Hundreds of homes are within a mile of the six-acre site but there actually are no back yards in the immediate vicinity, as it is a light-industrial area, bordered by a dozen lanes of interstate highway and an assortment of retail and nonretail businesses.

What appears to worry the residents most stands a quarter mile west of the proposed BESS facility: NYPA’s gas/oil-fired Flynn Power Plant, an LNG terminal and tank, and a petroleum tank farm served by a pipeline.

“If anything should go wrong, half of Long Island would disappear,” one woman said Thursday.

By late Friday afternoon, 56 public comments had been posted on the DPS website. As with the oral comments Thursday, one was in favor, the rest opposed.

All were submitted in the past week, as word spread about the plan.

Education Efforts

The New York State Energy Research and Development Authority is trying to drive further installation of energy storage as it leads the state’s energy transition efforts. The near-term goal is 1.5 GW by 2025, and the energy storage road map target is being revised from 3 GW to 6 GW by 2030.

NYSERDA is aware of public perceptions about BESS and is attempting to counter them with safety and quality-control protocols.

A spokesperson said NYSERDA works with host communities, developers and local, state and federal governments to ensure projects advance responsibly. It inspects any project supported by its programs. Its Clean Energy Siting Team has provided more than 200 free training sessions for local governments on planning and codes compliance.

NYSERDA has partnered with specialized contractors to provide technical assistance on fire safety, and with Underwriters Laboratories and other agencies to develop safety standards and test protocols.

And in June, NYSERDA published separate fact sheets for New York state and New York City explaining the differences between e-bike batteries and BESS. Both explain why BESS is critical to New York’s clean energy future and summarize the regulations that pertain to BESS, which differ between the city and the rest of the state.

The industry advocacy group New York Battery and Energy Storage Technology Consortium considers this type of outreach critical.

“There’s both a lack of information and there’s some misinformation out in the communities,” NY-BEST Executive Director William Acker told NetZero Insider. “We do see reactions that are based on quite a bit of concern. We’ve recently started working with the state and the city a bit more on getting information out to the community.”

It is important that storage developers reach out to residents early in the process, Acker said. “We’ve got a lot left to do as an industry.”

One issue is simply the mystique of a BESS, he said: What is in that row of shipping containers behind the barbed wire fence, and what does it do?

“They have trouble picturing what is a large battery system,” Acker said. “That’s where more education will be valuable.”

He could not speak to the specifics of the Holtsville project, as he is not aware of all of its details, but said the blast equation cited by one Holtsville resident — 110 MW of BESS equals 100 tons of dynamite — is not accurate.

An explosion is a sudden, rapid release of energy, and a large BESS potentially has a lot of energy to release, Acker said. But it should not happen all at once — every system installed in New York state is required to be certified under UL 9540 standards to slow that kind of thermal runaway and cascading failure.

But he added a caveat: “That’s all predicated on the system being installed and built to codes.”

Tragic Results

The same thing can be said for e-mobility batteries: They need to be made well and cared for properly. A lot of fires are blamed on defective or misused equipment.

Many of the ubiquitous e-bikes zipping through the streets of New York City are ridden by people trying to make a living in low-wage jobs in one of the most expensive cities in the nation. They buy what they can afford and recharge it wherever and whenever they can, sometimes improvising unsafely to make ends meet.

Underwriter Laboratories’ Fire Safety Research Institute identifies the common causes of Li-ion thermal runaway as mismatched parts, modifications, uncertified batteries and battery abuse.

And when failures occur, they can happen with stunning speed and intensity.

FSRI set up six interior and exterior video cameras and deliberately overcharged an e-scooter in the living room of a test site. Within 10 seconds of flames becoming visible, the scooter battery exploded, blowing out the windows and sending flames billowing through the structure.

And that is exactly what happened to a New York City man who spoke to The New York Times: When the battery in his secondhand e-scooter died and would not charge, he tried a succession of chargers until one seemed to work. Then the battery exploded. He was hospitalized for two months with severe burns, and his daughter died from smoke inhalation.

Process Continues

Thursday’s hearing was one part of one of the many federal, state, county and town reviews facing the Holtsville BESS project.

Holtsville Energy Storage LLC, a wholly owned subsidiary of Savion, in March petitioned the state Department of Public Service for a certificate of public convenience and necessity for the project. (Case 23-E-0142.)

It asked for a lightened regulatory regime and an expedited proceeding, as DPS has granted in other cases involving exempt wholesale generators.

Notwithstanding neighbor opposition to the project itself, no procedural objections were raised at Thursday’s hearing.

On Friday, a DPS administrative law judge granted the request, ruling that no requests had been made for an intervention in the proceeding or an evidentiary hearing and no material issues of fact were raised that would require either.

Savion, part of Shell, did not return a request for comment for this story.

The Holtsville Energy Storage petition estimates the total project cost at $160.6 million and says it will be covered through sponsor equity, tax equity and debt financing.

The BESS would be 124 Li-ion battery containers separated by distances that meet or exceed UL 9540a fire propagation standards. There would be switchgear for a 138-kV interconnection at an existing LIPA substation nearby.

The developer hopes to begin construction in late 2024 and begin operation in winter 2025.

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FERC Approves Revisions to SPP GI Process

FERC on Tuesday accepted SPP tariff revisions that clarify its interconnection (IC) customers’ financial security refunds, effective April 1, 2023, and subject to a compliance filing within 30 days of the order (ER23-841).

The commission found SPP demonstrated that the revisions are just and reasonable and not unduly discriminatory or preferential and would comply with FERC’s rulemakings concerning the pro forma generator interconnection procedures (GIPs) and agreements.

Under the revisions, SPP will determine whether an interconnection customer withdrawing its request after the first two decision points of the RTO’s three-phase GI study process is subject to forfeiting its financial security. SPP will evaluate the withdrawal’s effect on upgrade costs for “equally- or lower-queued” IC requests within the “actively studied clusters.”

FERC said the revisions “therefore clarify which interconnection requests are evaluated in SPP’s impact analysis.” It said the revisions improve certainty for IC customers, meeting the purposes of its pro forma GI procedures and agreements rulemaking.

In addition, SPP proposes revisions to GIP section 8.14(e) to apply the financial security forfeiture exemptions in GIP section 8.14(d) to interconnection requests that are subject to any restudies after Decision Point 2 that are performed in accordance with GIP sections 8.8 and 8.13.

The proposed revisions to GIP section 8.14(e) also provide that if an interconnection request is restudied and it meets the forfeiture exceptions under GIP section 8.14(d), the IC customers will have 15 business days after the restudy results are posted to decide whether to withdraw requests. The commission said the 15-day deadline “should help streamline the study process” by encouraging IC customers to make timely decisions about whether they intend to proceed to the next study stage after a restudy.

“We find that the proposed revisions … strike a reasonable balance between giving an interconnection customer an opportunity to withdraw from the queue without forfeiture of the [security] payments if allocated upgrade costs significantly increase after a restudy and allowing SPP to administer its queue in an efficient and timely manner,” FERC said.

Several renewable energy developers protested SPP’s proposal when it was filed in January, saying it reduces an IC customer’s ability to have its posted financial security refunded when withdrawing due to a substantial increase in allocated upgrade costs. They argued that the proposed revisions unreasonably deny IC customers the opportunity to claim a forfeiture exemption if the grid operator revises its second phase’s results without a restudy.

The commission approved SPP’s three-phase IC study process in 2019. (See FERC OKs New SPP Interconnection Process.)

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NYISO Stakeholders Still Questioning Interconnection Queue Proposal

ALBANY, N.Y. — NYISO on Thursday sought once again to clarify its Class Year queue window concept and assuage stakeholder concerns expressed in previous meetings about the proposed changes to the interconnection study process.

Thinh Nguyen, NYISO senior manager of interconnection projects, told members of the Transmission Planning Advisory Subcommittee that “we want to make sure that we’re reducing [interconnection] timelines and that this is an ongoing discussion amongst stakeholders.”

Stakeholders, however, remained skeptical and had many unresolved questions.

“We’ve been pointing out each time we have these meetings that we need a focused presentation on how much of our extra work translates into extra benefit,” said Mark Reeder, representing the Alliance for Clean Energy New York, referring to how the new construct would have developers complete many pre-application requirements before being able to join, which has caused confusion.

Comparison of NYISO’s current and proposed interconnection queue concepts | NYISO

This comment was representative of the struggle stakeholders have expressed previously to NYISO, as the ISO has reworked the proposal throughout the year. (See NYISO’s Latest Queue Overhaul Draft Confuses Stakeholders.)

Stakeholders still wanted more clarity about many parts of the concept, including project prioritization and potential off-ramps for large generators.

Doreen Saia, an attorney with Greenberg Traurig, asked about project prioritization and whether Group A projects that finish their cluster feasibility studies could be impacted by the feasibility results of Group B projects.

“Group A projects have priority against Group B. So, when you add Group B into the Class Year study, if there’s a problem, then Group A has a much higher priority,” Nguyen responded.

“I am worried that you could inadvertently undervalue the whole [concept],” Saia followed up. “If Group A projects do great, but then Group B projects come out and it is an unholy mess, [developers] may now decide they aren’t willing to agree to new costs 90 days after their initial costs for Group A projects were determined.”

Reeder asked whether NYISO has begun considering allowing off-ramps for large-scale projects that want to withdraw from the queue after discovering they might be infeasible. NYISO currently allows only small generators to withdraw from the queue without penalty.

Nguyen responded, “This is still on the table, but we’re still going to have to think about that.” Nguyen added that NYISO is aware that there are many circumstances in which a large-scale generator may need to withdraw for valid reasons.

NYISO will refine the proposal until the fall, when it will begin vetting tariff language with TPAS. It asked that comments or questions be sent by July 21 so they can be incorporated into the next meeting presentation Aug. 1.

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ACEEE Report: Some States not Taking EVs Seriously

President Joe Biden wants 50% of all new car sales across the U.S. to be zero-emission vehicles by 2030, and according to a new report from the National Renewable Energy Laboratory (NREL), meeting that goal could require a nationwide network of 28 million charging ports, the majority of which would be located at single family homes.

Intended as a basic needs assessment, the 2030 National Charging Network report estimates 26.8 million Level 1 and Level 2 (L2) charging ports will be needed at single family homes, multifamily dwellings and workplaces. Another one million L2s should be installed in publicly accessible locations near homes and workplaces ― for example, in urban neighborhoods and at retail outlets ― while 182,000 DC fast chargers would be located along highway corridors and in rural or remote communities.

“In contrast to gas stations, which typically require dedicated stops to public locations, the [plug-in EV] charging network has the potential to provide charging in locations that do not require an additional trip or stop. Charging at locations with long dwell times (at/near home, work or other destinations) has the potential to provide drivers with more convenient experiences,” the report says.

But DC fast chargers are critical for “long-distance travel and ride-hailing, and to make electric vehicle ownership attainable for those without reliable access [to] charging while at home or at work,” a demographic that could represent about 3 million vehicles by 2030, the report says.

The report projects those chargers could be powering anywhere between 30 million and 42 million EVs but bases its topline calculations on a “mid-adoption scenario” of 33 million EVs on the road by 2030. The price tag has an even wider range, between $53 billion and $127 billion, due to “variable and evolving equipment and installation costs observed within the industry across charging networks, locations and site designs,” the report says.

The big numbers in NREL’s needs assessment are daunting in the face of current figures from the Department of Energy, counting about 140,500 publicly accessible charging ports spread across 54,200 locations. State and local policies could play a major role in bridging that gap, but according to a second report from the American Council for an Energy-Efficient Economy (ACEEE), planning for EV adoption and charging in many states is moving at a crawl.

The 2023 State Transportation Electrification Scorecard ranks states across a range of EV policies — from planning to consumer incentives to utility policies and grid optimization. The highest possible score is 100, but ACEEE found 17 states with so few points, they weren’t included on the scorecard. Only nine states scored more than 50.

California (88 points) took the No. 1 spot, followed by New York (62) and Colorado (61). Massachusetts, Vermont, Washington, New Jersey, the District of Columbia and Oregon all scored in the 50s.

“We are seeing incremental progress, not transformational progress. States will have to move far more aggressively to do their part to enable the electric vehicle transition that the climate crisis demands,” said Peter Huether, senior research associate at ACEEE and lead author of the report. “Auto manufacturers are expanding their EV options and consumers are increasingly choosing them, but supportive state policies are needed to ensure that the electric grid is ready and that all households and businesses, including those in underserved communities, can use EVs and have adequate access to charging.”

The challenges ahead for a build-out of charging infrastructure include a lack of regulations that require both utility planning and the adoption of EV-ready building codes, according to the ACEEE report. Less than half of the states are requiring utilities to plan for the installation of chargers, both private and public, though many utilities are planning for EV charging, Huether said.

Even fewer states ― 12 in all ― have EV-ready building codes, for example, mandating that new construction either be wired for or include charging stations. Having the wiring for charging built in will be especially important for multifamily housing, where residents may be wholly dependent on public chargers.

A Patchwork of State Policies

The transportation sector accounts for the largest portion of U.S. greenhouse gas emissions ― 28% versus 25% for the electric power industry, according to the U.S. Environmental Protection Agency.

Biden has made transportation electrification a cornerstone of his drive to reduce the country’s GHG emissions 50% to 52% by 2030, in line with his commitment under the Paris climate accords. Major automakers have followed suit with commitments to sell increasing numbers of electric vehicles within the next 10-20 years.

General Motors has pledged to go all electric by 2035, while Ford has said it is targeting 50% electric vehicle sales by 2030.

California also has set the pace with its Advanced Clean Cars II rule, requiring all new passenger cars, trucks and SUVs sold in the state to be electric or zero-emission by 2035. Five states — Massachusetts, New York, Oregon, Vermont and Washington — also have adopted the rule.

But outside these states — all in ACEEE’s top nine — what both reports show is a patchwork of EV adoption and charger installation across the country, with a range of variables either accelerating or slowing down electrification of the transportation sector.

For example, the NREL report calls for 182,000 DC fast chargers on highways versus the 500,000 goal Biden set for the National Electric Vehicle Initiative (NEVI) program funded with $5 billion from the Infrastructure Investment and Jobs Act.

Initially, the proposed guidelines for NEVI called for all chargers funded by the program to be at least 150-kW DC fast chargers, but the final guidelines issued in March allow a mix of fast and L2 chargers, reflecting trends in EV adoption and charger use.

Eric Wood, a senior EV charging infrastructure researcher at NREL, said the charging network study “exhaustively considers how people in the U.S. use light-duty cars to travel, what their energy needs are for that travel, and how we can meet those needs, given projected EV adoption rates.”

“Detailed transportation data … enabled the team to answer questions like: How will EV adoption in neighboring states impact the demand for public fast charging along highway corridors in my area? And how might that out-of-state demand compare to charging needs from residents in my area?” Wood said in a blog post on the report.

The report itself points out that while prospective EV buyers prioritize the availability of fast chargers, “consumer preferences tend to shift after an [EV] purchase is made and lived experience with charging is accumulated. Home charging has been shown to be the preference of many [EV] owners due to its cost and convenience.

“This dichotomy suggests that reliable fast charging is key to consumer confidence, but also that a successful charging ecosystem will provide the right balance of fast charging and convenient destination charging in the appropriate locations,” the report says.

Balancing of the supply of chargers with the deployment of EVs is another critical issue that must be worked out on the local level, the report says. “Actual charging infrastructure will likely be necessary before demand for charging materializes.” Having chargers on the road is, again, essential for building consumer confidence, but “infrastructure investment should be careful not to lead vehicle deployment to the point of creating prolonged periods of poor utilization, thereby jeopardizing the financial viability of infrastructure operators,” the report says.

Oklahoma Most Improved

The uneven distribution of EVs and EV chargers will likely continue, according to the NREL report. Looking ahead to 2030, the report estimates that California will have more than 7.3 million EVs on the road and 262,100 publicly accessible L2 chargers versus Wyoming, which will have 50,000 EVs and 2,100 public chargers.

ACEEE’s Huether said he hopes the combination of industry commitments and federal action – like NEVI and the EV tax credits in the Inflation Reduction Act – will spur more states to start planning.

Certainly, population numbers and demographics are central factors for some states, but “there are states that are just not taking transportation electrification seriously,” he said in an interview with NetZero Insider. “Maybe that’s because they don’t see it as much in their state, or they don’t recognize the benefits as much.”

Although many of the low-scoring states have Republican-dominated governments, Huether said the split between high- and low-scoring states on the scorecard is not purely political. “Oklahoma was our most-improved state in terms of rank,” he said, moving up eight spots. The state has the highest proportion of DC fast chargers per capita and has “done a lot of work around electric school buses,” he said.

Another anomaly, particularly in the Southeast, is the split between the billions of dollars in incentives states have offered to EV and EV battery plants to locate there and their low rank on the scorecard. According to ACEEE, Georgia leads the list with $3.6 billion in subsidies to manufacturers but is No. 32 out of 33 on the scorecard.

States like Georgia are “spending a lot of money to attract these companies [but] they’re not setting up their state, setting up drivers in their state to really benefit,” Huether said. “They recognize maybe the broader economic manufacturing benefits, but not the benefits of having those vehicles in their state. We really implore them to be clear, more proactive in adopting some of these policies.”

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Former Ohio House Speaker Householder Sentenced to 20 Years in Prison

A federal judge in Cincinnati sentenced former Ohio House Speaker Larry Householder (R) to 20 years in prison Thursday for taking bribes from FirstEnergy to pass legislation subsidizing the company’s nuclear plants.

U.S. District Judge Timothy Black ordered Householder handcuffed before deputies took him from the courtroom despite a request by his attorney to allow him to report to prison later.

Householder asked the judge for clemency on behalf of his family before he was sentenced. He is expected to appeal. Federal prosecutors asked for the maximum sentence of 16 to 20 years. Co-conspirator Matt Borges, a former Ohio Republican Party chairman, is scheduled to appear before Black for sentencing Friday.

“Larry Householder led a criminal enterprise responsible for one of the largest public corruption conspiracies in Ohio history,” U.S. Attorney Kenneth L. Parker said in a statement following the hearing. “Elected officials owe a duty to provide honest services to their constituents — transparency, integrity and accountability are foundational principles of democracy. Householder once held one of the three most powerful offices in the state of Ohio. Now, because of his corruption, he will serve a substantial prison sentence.”

“The people of Ohio are the true victims of Larry Householder’s corrupt scheme to increase his power and pass a billion-dollar corporate bailout,” FBI Cincinnati Special Agent in Charge Will Rivers said. “While we hope this sentence clearly demonstrates that corruption does not pay, the FBI will continue to investigate and pursue those who abuse their positions and take advantage of the public.”

A jury in March found Householder and Borges guilty of racketeering conspiracy charges connected to a yearslong conspiracy orchestrated with FirstEnergy. (See Householder Convicted in FirstEnergy Bribery Case.) Both men have been free on bond.

The arrangement enabled the speaker to funnel cash through two dark money groups to fund the election campaigns of allies in both chambers of the legislature who favored a public bailout of the company’s uncompetitive Ohio nuclear power plants.

Lawmakers approved the legislation, House Bill 6, in July 2019. Householder and the company, again using dark money connections, defeated a ballot issue nullifying the legislation. A federal grand jury indicted Householder and four others in July 2020. The legislature later removed the nuclear subsidy from the law but kept an unrelated subsidy for two 70-year-old coal power plants on the Ohio River.

Despite moving the ownership of the nuclear plants to a subsidiary several years earlier, FirstEnergy had sought ratepayer funding for them as early as 2014 in a case before the Public Utilities Commission until FERC intervened. The company’s lobbying efforts for legislation creating a public subsidy died in legislative committees.

FirstEnergy, identified as “Company A” in the 2020 indictment, denied wrongdoing but then agreed to pay a $230 million fine in a deferred prosecution agreement. (See DOJ Orders $230 Million Fine for FirstEnergy.) Former CEO Charles Jones and Michael Dowling, senior vice president of external affairs, were fired in October 2020.

The federal probe also prompted the company to reorganize its board of directors, creating a watchdog committee to investigate top management’s ethical practices. Several other senior managers have since been fired.

“Millions of Ohio utility consumers are seeing a measure of justice today, regarding the tainted House Bill 6, with the federal judge’s sentencing of the former speaker of the House,” Ohio Consumers’ Counsel Bruce Weston said in a statement. “But more justice needs to be served. More justice should include the legislature repealing the coal power plant subsidies that the scandalous legislation still requires Ohioans to pay to AEP, Duke and AES.

“More justice also should include the [Public Utilities Commission of Ohio] lifting its stay on our and others’ investigations into any improper charges to consumers by FirstEnergy.”

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Interconnection Costs on the Rise, Berkeley Lab Study Finds

Interconnection costs are on the rise across the U.S., according to a Lawrence Berkeley National Laboratory analysis of thousands of projects in five organized electricity markets.

The team manually scraped cost estimates from 2,500 interconnection studies from ISO-NE, MISO, NYISO, PJM and SPP, LBNL policy researcher Joachim Seel said during a webinar Thursday. CAISO has stronger data privacy rules than others, while ERCOT uses a “connect and manage” system that limits the amount of upgrades developers must pay for. Non-RTO regions generally do not release such information.

“Collecting this cost data has been quite difficult as the cost estimates are often the only available interconnection study PDFs, [and] that required time-intensive manual scraping,” Seel said. “We’ve cleaned and sanitized the data and made much of the underlying project cost data available on our website. And to our knowledge, this is really the first time that this data can be easily accessed.”

The data collection was partially funded by the U.S. Department of Energy’s Interconnection Innovation e-Xchange (i2X) process, said DOE’s Cynthia Bothwell, who helps run the exchange created to enable simpler, faster and fairer interconnection of clean energy resources.

“The motivation for the cost analysis that you’re going to hear about more today was that we found it very hard to get information,” Bothwell said. “Developers said, ‘You know, we don’t know how much things cost, [or] where we can interconnect, and a lot of other issues.”

While the data was public, it was not easy to gather — taking hundreds of worker hours per market to compile. Now the industry will have a central place to look up interconnection cost information, she said.

The LBNL team plans to continue collecting data, including eventually from CAISO and traditionally regulated utilities, and performing additional analyses, Seel said. While costs have been trending up, they vary greatly by project type and other factors, meaning they are “not normally distributed,” he said.

“There are many projects with rather low interconnection costs, but also some projects with very high interconnection costs,” he said. “And although these high-cost projects may be fewer in number, their high project costs can influence the sample mean quite a bit and pull it upward.”

Out of the projects that have made it through PJM’s queue since 2017, nearly 120 had interconnection costs of $25/kW, but some were several times higher than that — with a few at $450/kW.

Costs have been on the rise over time, and LBNL broke down projects by complete, pending and withdrawn, with those pulling out of the process having the highest average costs and completed projects the lowest, Seel said.

Newer projects must generally pay for more broad transmission network upgrades triggered by reliability or stability violations found in the modeling of the proposed resource. That could involve reconstruction of high-voltage transmission lines as renewables are often in more rural areas where the grid is weaker.

Breaking Down by Project Type

The analysis also found differences among technologies, with solar costs remaining fairly consistent across regions, and completed projects spending between 5% and 10% of their total capital on interconnection upgrades, while withdrawn projects faced interconnection costs comprising 20% to 40% of their total capex.

Storage projects also face high costs, which Seel said could be due to their being built in congested parts of the grid to benefit from energy arbitrage opportunities.

Onshore wind has greater variation, with completed projects spending between 3% and 16% of their total budgets on interconnection and withdrawn projects 10% to 40%.

The onshore wind numbers were particularly skewed by ISO-NE, where nearly all proposals since 2018 have withdrawn after facing huge interconnection costs that run up to $800/KW, LBNL’s Julie Kemp said.

“For onshore wind, all of the recent projects are located in Maine, and many of them are in quite remote areas where the existing transmission system is pretty limited,” said Kemp. “And, so, these high costs that we see are the result of the significant buildup that would be required to connect substantial new generation in these areas that currently do not have much load or much generation.”

An LBNL graphic showed the highest interconnection costs for wind in Aroostook County in the state’s far north, where the limited transmission system is not even operated by ISO-NE, but rather the Northern Maine Independent System Administrator.