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November 1, 2024

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New Jersey Backs $150 Million Hike for Offshore Wind Transmission

The New Jersey Board of Public Utilities (BPU) on Thursday approved an additional $150 million of expenses for the state’s $1.07 billion transmission project to connect offshore wind farms to the grid, saying the extra cost would not undercut the project’s financial benefits for ratepayers.

The 14% increase follows by eight months the board’s approval of the project in what the agency said was the first use in PJM of FERC’s state agreement approach (SAA), which allows a state or group of states to initiate a project to fulfill state policy requirements as long as they foot the bill for associated costs in the RTO’s transmission plan.

The cost rise comes amid growing scrutiny of New Jersey’s ambitious clean energy commitments, especially the plan to develop 11 GW of offshore wind capacity, with some Republicans and business groups demanding an estimate of the cost to ratepayers and questioning whether the investment is worthwhile.

As the BPU acted, state lawmakers in a last-minute vote before the summer recess backed a bill that would enable Danish developer Ørsted to receive federal tax credits to help meet cost increases in its Ocean Wind 1 project, rather than the state receiving the benefits of the credits. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)

“We have to keep moving forward,” BPU President Joseph L. Fiordaliso said before the board’s 5-0 approval of the order outlining the increase. “There are unfortunately many unforeseen developments that have occurred over the past couple of years prior to the pandemic and after the pandemic as far as the economy is concerned, where we see increases that were never anticipated.”

The BPU endorsed additional expenses of $40.76 million for several changes — described as “interconnection work” — in the scope of work, or additional elements of construction that were not part of the original bids approved in the solicitation. Part of that expense will pay for the engineering, procurement and construction of cables and connection points that would tie the offshore projects to the grid.

The interconnection cost increases also included Jersey Central Power & Light’s replacement of 115- and 230-kV transmission lines to make way for larger lines, and the replacement of certain equipment.

The board also approved $109.5 million in “scope-related cost estimate adjustments,” cost increases resulting from a closer analysis of the developer’s work and estimates. That included $27.1 million for the “reconductor of a small section” of a 230-kV line as a result of “updated communication between the developer and PJM,” which is a partner to the BPU in the SAA project. An additional $71.9 million stemmed from the “additional refinement” of the developer’s “cost estimates for their awarded scope,” which the BPU expected at the time the offshore wind project was awarded, the order states.

The $109.5 million estimate was reduced from the previously released revised estimate of $127.34 million, which was first reported at a May 9 meeting of the PJM Transmission Expansion Advisory Committee. (See NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint.)

Ratepayer Benefits of Offshore Wind

Andrea Hart, BPU’s senior program manager for offshore wind, told the board the changes would not affect the agency’s estimation that the selected SAA solutions would save ratepayers more than $900 million, a figure calculated by looking at the “cost of the transmission facilities that would be necessary to achieve New Jersey’s offshore wind goals in the absence of an SAA solution.”

That’s because, according to The Brattle Group, a consultant working on the project, the cost increases would have been incurred anyway had the agency opted to tie in the offshore projects to the grid using a non-SAA agreement approach.

“Clearly, price increases are not uncommon,” said Commissioner Zenon Christodoulou. “But as a consumer, they’re never welcomed. So although we accept this and we appreciate all the efforts, I think that additional changes might not be as welcome.”

Brian Lipman, director of the New Jersey Division of Rate Counsel, who first raised concerns about the hikes in June, said he was “skeptical that these increases result in no change to the amount of benefit to be seen by ratepayers.”

“We still question whether the scope changes are in fact prudent increases,” he said in an email to NetZero Insider. “It is unclear to Rate Counsel why some of these issues were not identified in the initial bid.  While we understand that some changes may be necessary (equipment not available or has been updated) these changes appear to be due to a failure to fully understand the project when bid.

“These increases are not due to changes in economics or increases in materials,” he wrote. “These changes are coming about because as the developers take a closer look at the work they bid to do, they realize that changes need to be made.”

Anticipated Future Hikes

The BPU awarded the main part of the SAA project — costing $504 million — to Mid-Atlantic Offshore Development (MAOD) and JCP&L to build a new substation called the Larrabee Tri-Collector Solution next to an existing JCP&L substation through which offshore wind projects would tie into the grid. The agency also awarded contracts totaling $575 million to seven smaller projects to upgrade existing onshore transmission identified by PJM as necessary.

The agency’s awards focused only on infrastructure on land, leaving the offshore infrastructure to be completed later by offshore project developers. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)

The order approved by the BPU last week said the original project selection anticipated that additional interconnection work would be needed but did not define whether it would be done by the SAA project developer MAOD or an offshore wind developer. Documents for the BPU’s third offshore wind project solicitation, released in March, outlined the winning developer’s responsibility for “prebuild infrastructure” that would build the necessary duct banks and access cable vaults to be used by all offshore wind projects to the new Larrabee substation.

The solicitation documents did not specify whether MAOD or the winner of the third solicitation would build certain parts of the infrastructure, and the BPU and its consultants recently concluded that the work would be best done by MAOD, adding to its costs, the order said. Pursuing that option would allow the work to be completed faster than waiting for the third solicitation process to be completed, would be safer and would yield various technical benefits, the order said.

The work included the engineering, procurement and construction of infrastructure to “accommodate” four HVDC lines and the work needed to design and build the trenches and collector lines for three alternating current lines, the order said.

“As transmission projects develop, it is common, if not expected, for cost estimate adjustments to occur,” the order states. “As such, additional cost estimate adjustments, in addition to the cost estimate adjustments noted herein, may be anticipated in the future.”

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ISO-NE Considers Major Capacity Market Changes

MANCHESTER, Vt. — ISO-NE is considering moving to a prompt and seasonal capacity market, the organization told stakeholders at its Participants Committee (PC) summer meeting last week.

The RTO has emphasized the need to address the seasonal variance of resource reliability in its capacity market, especially as it expects to transition from a summer peaking to a winter peaking system. The organization outlined potential options for transitioning to such a market, while also accounting for the implementation of Resource Capacity Accreditation (RCA) updates, which likely would affect the scheduling of future capacity auctions.

The RCA project has been an extended effort by the RTO to better assess the reliability of various resource types, which ISO-NE was hoping to implement for Forward Capacity Auction (FCA) 19, which would procure capacity for the 2028-29 capacity commitment period (CCP).

However, ISO-NE announced in June that it had found an error in the software used in the RCA project, which caused an underestimation of the amount of LNG available to generators when assessing winter risk. The RTO has said this error affected several months’ worth of work on the project and will affect its implementation schedule.

In a memo written prior to the PC meeting, ISO-NE Chief Operating Officer Vamsi Chadalavada asked for stakeholder feedback on the best way to incorporate the RCA project into the forward capacity auctions. ISO-NE also highlighted the potential of moving away from the current forward capacity market structure and holding auctions seasonally and just a few months ahead of the CCP.

ISO-NE wrote in the memo that moving to a prompt capacity market would buy time for the RTO to implement the market changes.

“In transitioning from a three-year forward to a prompt capacity market construct, there will be up to a three-year period between conducting the final forward capacity auction and conducting the first prompt capacity auction,” Chadalavada wrote.

David Patton of Potomac Economics, which serves as ISO-NE’s external market monitor, recommended transitioning to prompt and seasonal market as soon as feasible and said a seasonal market would do a better job accounting for the differences in seasonal reliability between resources.

Patton said the current process has a “a dubious track record of facilitating entry of new resources,” and that procuring capacity three years ahead “inhibits resources with fast development timeframes from receiving revenues as soon as they are able to support reliability.”

He noted that the existing FCA structure introduces uncertainty into the expected load and resource mix and added that the current market can also lead to premature retirement of older existing resources.

“Retirement of older units is often prompted by unforeseen equipment failure that is not economic to repair,” Patton said. “Such units must accept a capacity obligation that ends more than four years after the FCA, which creates substantial risk for the supplier.”

Presenting a cross-market comparison between ISO-NE and other RTOs, Patton found New England had the highest all-in costs in 2022, largely consistent with previous years. Patton said that higher gas prices in the region drive the higher overall costs but added that New England also has the highest capacity charges, largely due to “over-forecasted demand ahead of the FCAs, which are slow to correct.”

Comparison of RTO all-in prices | Potomac Economics

ISO-NE laid out four potential pathways for implementing the RCA updates as well as a prompt and seasonal capacity auction, including the possibilities of delaying FCA 19, delaying the RCA implementation and/or implementing a prompt and seasonal market along with the RCA changes for either the 19th or 20th auction cycle. The RTO noted that the removal of the Minimum Offer Price Rule will proceed for the 2028-29 CCP as scheduled.

Aleks Mitreski of Brookfield Renewables expressed his opposition to delaying FCA 19 due to the uncertainty this could introduce.

“ISO-NE has a great track record of never delaying an auction, so having FCA 19 run as scheduled will avoid market uncertainty and any regulatory uncertainty if the delay is challenged at FERC,” Mitreski said in a statement to RTO Insider. “By pushing the RCA implementation for FCA 20, this will give the stakeholders time to evaluate the RCA changes, as well as the benefits and tradeoffs for implementing a seasonal and/or prompt capacity market.”

Mitreski added that a move to a prompt and seasonal market would introduce several tradeoffs, and that stakeholders will need time to evaluate the merits of such a change.

“While it will help with the fuel qualification processes for RCA, a prompt market does not enable new entry in the market to address any retirements or transmission issues,” Mitreski said. “The only fix for those reliability issues would be expensive out-of-market reliability-must-run agreements like we have seen in NYISO in the past, something that the New England region wants to avoid.”

Budget Increase

ISO-NE also told the Participants Committee that it expects a significant year-over-year increase for its 2024 budget in its presentation on its preliminary budget for the coming year, equaling a 21.5% increase in the total revenue requirement for 2024.

This increase is driven by increased costs related to preparing for the clean energy transition, effects of inflation on labor and information technology costs, and the net-change from the annual revenue true-up, the RTO said. The largest single portion of the increase is associated with adjustments to employee salaries.

ISO-NE preliminary 2024 budget | ISO-NE

“The 2024 budget represents a ramping-up of organizational capacity to carry out the organization’s mission of planning the transmission system, administering the region’s wholesale markets, and operating the power system to ensure reliable and competitively priced wholesale electricity; as well as developing new capabilities that will be necessary for supporting the grid of the future,” ISO-NE CFO Robert Ludlow said.

Ludlow said that the RTO needs to increase staffing to meet clean energy planning needs, noting that the changing resource mix and the overall increase in generating assets will increase the organization’s workload. For 2024, the RTO proposed the addition of 40 new full-time employees, 34 of whom would be focused on supporting the clean energy transition.

“In order to keep pace with the needs of the transition to cleaner generating resources, the ISO must begin ramping up its capabilities and operational capacity now,” Ludlow said.

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FERC Accepts NYISO’s Revisions to CRIS

FERC on Friday accepted NYISO’s proposed tariff revisions that it said will prevent generators not using their capacity resource interconnection service (CRIS) rights from retaining them and allow for more efficient transferring (ER23-1824).

The revisions are intended to make it easier for deactivated facilities to adjust their unexpired CRIS rights while also increasing capacity deliverability headroom and potentially lowering the cost of market entry for future facilities by lessening the need for deliverability upgrades.

CRIS is required to participate in NYISO’s capacity market and can only be obtained either through a transfer from a facility with existing rights or from ISO deliverability studies.

“NYISO’s proposal adds greater clarity and flexibility regarding the rules applicable to CRIS transfers and bolsters the existing CRIS retention and termination rules,” FERC said. “We agree with NYISO that these revisions will help facilitate the full and efficient utilization of existing interconnection capacity by mitigating the retention of CRIS by suppliers who are not fully utilizing or who are unable to fully utilize their CRIS, and by enabling the more efficient transfer of CRIS between facilities.”

NYISO had been working on the revisions since 2020. (See “CRIS Revisions Approved,” NYISO Management Committee Briefs: Jan. 25, 2023.)

The Long Island Power Authority and energy storage development company Elevate Renewables F7 did not oppose NYISO’s proposal, but they suggested several changes to address concerns they had with it. As they did not lodge any protests against the filing, FERC did not address their concerns, ruling their suggestions outside the scope of the proceeding.

The changes went into effect Monday.

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North Carolina Businesses Endorse Market Reform Studies

A group of North Carolina businesses urged the state’s legislature and governor to support studying “wholesale market competition options,” including an RTO, saying they were “concerned over limited access to cost-competitive, clean energy.”

In a letter sent Thursday to the General Assembly and Gov. Roy Cooper (D), the businesses endorsed North Carolina House Bill 503, introduced in March. The bill would direct the North Carolina Collaboratory — a clearinghouse established among the state’s public universities to provide useful research data to state and local governments — to “evaluate reform of the [state’s] regulatory wholesale electricity market.”

Studies undertaken under the bill would have to include an evaluation of designated market structures — an RTO within either North and South Carolina or the entire Southeast U.S.; an energy imbalance market within the same areas; or participation in the Southeast Energy Exchange Market (SEEM) — along with “any other market reforms the Collaboratory [deems] appropriate.”

In May, the South Carolina Legislature received a report that said participating in an RTO could provide the state benefits of up to $362 million per year. (See Brattle Report Sees Benefits for SC RTO Membership.)

Signers of the letter include hotel chain Marriott, food and beverage brands Sierra Nevada and Nestle, solar power developer Carolina Solar Energy, and Unilever, along with advocacy groups such as the Carolina Utilities Customer Association and the Clean Energy Buyers Association (CEBA).

In a statement on CEBA’s website, Reese Rogers, the organization’s Southeastern market and policy innovation manager, said “expanding [the state’s] market options … would help drive innovation and cost savings for all energy customers and improve grid reliability and resilience.”

“House Bill 503 would open a path for North Carolina to move toward greater options for customer choice and grid reliability,” Rogers added.

Despite the legislation’s nod toward SEEM, CEBA has been an active opponent of the market since it was proposed. It is party to a lawsuit in the D.C. Circuit Court of Appeals seeking to overturn SEEM’s approval by FERC in 2021. (See Environmental Groups Appeal SEEM in DC Circuit.)

Topics to be examined under the legislation include the costs, benefits and risks to a range of stakeholders from both the state’s current electric system and potential market changes in terms of generation capacity adequacy and diversity, customer service and rates, environmental quality, and other factors. The Collaboratory would also be tasked with identifying any laws, regulations and policies that may need to be changed to implement reforms, their impact to disadvantaged populations and communities, and any challenges associated with nuclear plants within the state.

While the proposed studies do not specifically mention reliability, the topic is prominent in the bill’s introduction, which says “North Carolina must be prepared for future weather events,” such as the 2022 holiday storms that led Duke Energy to implement rotating outages that left about 500,000 customers without power. (See North Carolina Regulators Face Questions on Holiday Outages.)

The introduction links the topics of reliability and market reform by noting that the state’s electricity is predominantly “provided by vertically integrated … distribution and transmission” utilities, and citing previous legislation requiring utilities to “diversify the resources used to reliably meet … energy needs.”

The businesses’ letter also referred to the winter storm blackouts, saying they “highlight the urgent need for sufficient reliable and affordable electricity in North Carolina.” The businesses added that the “ability to source clean, competitively priced [reliable] electricity … is a core factor in where we decide to make or maintain investments” and warned that “limited access to cost-competitive, clean energy” might discourage companies from doing business in the state.

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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.)