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November 17, 2024

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DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study

The U.S. Department of Energy has announced two actions to support the expansion of the transmission grid: investing up to $1.5 billion in four specific projects around the country and releasing the final National Transmission Planning Study. 

The $1.5 billion investment from the Transmission Facilitation Program was authorized by the Infrastructure Investment and Jobs Act. DOE is giving the money upfront to four projects, which eventually can sell it to actual users, at which point the department will get its money back to use on future transmission projects, Deputy Energy Secretary David Turk said on a call with reporters Oct. 1.

“Like many things about the clean energy transition, building new transmission is extremely challenging, and it’s also extremely urgent,” Turk said. 

DOE announced the first three lines under the TFP last fall; all three have signed deals with the department, Turk said. In total, the TFP should help build more than 3,000 miles of new transmission by early next decade. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

Avangrid Network’s Aroostook Renewable Gateway in Northern Maine will negotiate for DOE for funding of up to $425 million to build the 111-mile project that seeks to link up to 1,200 MW with ISO-NE. The region lacks direct connections with the rest of New England, and the line would help three mature wind projects connect to the market, with the potential for more wind and solar development. 

Invenergy’s Cimarron Link Transmission is negotiating for TFP funds of up to $306 million to build its 400-mile HVDC line running from Oklahoma’s panhandle to Tulsa in the east, opening 1,900 MW of transfer capacity that can deliver wind and solar to load centers.

Pattern Energy’s Southern Spirit Transmission project also is up for negotiations for $360 million to help get the 320-mile, 525-kV HVDC line that would connect ERCOT to the Southeast. The line can ship up to 3,000 MW of renewables from Texas to the Southeast and can ship power the other way if demand spikes in Texas. 

Southern Spirit could better help ERCOT make it through a cold snap, avoiding some of the devastation seen during Winter Storm Uri in 2021, White House National Climate Advisor Ali Zaidi said. 

“This buildout is really transformational in breaking down the barrier between ERCOT and the rest of the country, and it feeds into this broader insight that this administration has pushed, which is essentially [that] interregional transmission translates to lower costs for consumers and higher reliability across the system,” Zaidi said. 

Southern Spirit has been under development for years, with FERC finding in 2014 that it would not trigger federal regulation over ERCOT, according to a fact sheet from Pattern. 

Phase 2 of Grid United and Black Forest Partners’ joint Southline Transmission Project would add a 108-mile, 345-kV line capable of delivering 1,000 MW of capacity across New Mexico, helping to support electricity delivery in the Southwest. It is up for $352 million. Southline Phase 1 was in the first set of projects announced last year. 

“You need only to look at the recent devastation of Hurricane Helene to know how the climate crisis is already straining our existing grid infrastructure at the precise moment when we need that infrastructure to be larger, stronger and more reliable,” White House Senior Advisor John Podesta said.

National Transmission Planning Study

The National Transmission Planning Study features a set of long-term planning tools and analyses that examine potential scenarios through 2050, including various interregional transmission expansions. 

It shows the highest level of grid reliability can be maintained at the lowest cost by coordinating interregional transmission. The study was developed by the DOE Grid Deployment Office alongside the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, who said they want other planners to use it in their efforts. 

A substantial expansion of the transmission system throughout the entire contiguous U.S. delivers the largest benefits of up to $270 billion to $490 billion through 2050. Every dollar invested in transmission leads to returns of $1.60 to $1.80 in system costs saved, the study found. 

Being able to coordinate resource adequacy across better connected regions lowers systems costs by $170 billion to $380 billion, the study found. 

The use of HVDC transmission technologies with multiple terminals — meaning power can be sent bidirectionally and from multiple entry and exit points in regions — was shown to be the most cost-beneficial way to stitch together a macrogrid across the Lower 48. 

“When translating zonal scenarios to nodal network models, HVDC was found useful for transferring power over long distances and between interconnections, but AC network expansion will continue to be the best solution for a large portion of transmission additions,” the study said. “Large interregional HVDC network solutions will also require additional strengthening of the regional AC networks they interconnect.” 

DOE has been working on the NTP since 2022. Its goal was to identify pathways that maintain current levels of reliability and saving costs while meeting local, regional and national interests, Grid Deployment Office Director Maria Robinson said on a call with reporters. 

“This study goes down to the nodal level, instead of at the zonal/regional level, and that means that this is a tool that utilities can actually use to help them determine what kinds of investments that they might want to make,” Robinson said. 

So far, interregional transmission plans have been limited, with Robinson pointing to MISO and SPP’s Targeted Interconnection Queue Study as a rare example of it actually happening. 

“So, this is why we think it’s important to make sure that these tools are available, so that it is easier for those folks who are looking to do so, and also so that we’re able to use the best-in-class modeling available from the National Laboratories,” she added. 

DOE is not going to tell FERC how to do its job, she added. Chair Willie Phillips has said the commission could look at interregional planning in the future, noting that NERC’s interregional transfer capability is due at the end of the year. (See Webinar Examines How FERC Could Use Interregional Transmission Study.) 

The department has provided some technical assistance to NERC on its interregional transfer capability study and offered updates on what was being developed in the NTP, Robinson said. 

“Of course, while doing coordination, it doesn’t mean that the exact thing will happen in both places,” Robinson said. “So, we are really looking forward, as everyone else is, to seeing the ultimate results come out of that study. But a lot of the fundamentals are relatively similar, and it’s just nice to see this greater interest in interregional transfer capacity, understanding that it can be so important in times like right now in extreme weather events.” 

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CAISO Launches Phase 2 of Pricing Issues Initiative

CAISO on Sept. 30 launched Phase 2 of its Price Formation Enhancements Initiative, aimed at addressing issues specific to market power mitigation, scarcity pricing and fast-start pricing in its markets — including the Western Energy Imbalance Market and Extended Day-Ahead Market.

“These enhancements aim to improve the accuracy of our market clearing prices, provide better market price signals, and enhance incentives for resources to perform,” James Friedrich, CAISO lead policy developer, said during a meeting to launch the effort. “It is the general view of the [Price Formation Enhancements] working group that enhancements in these areas could help the market become a more effective steward of reliable outcomes.”

Phase 1 of the initiative hosted 18 working group meetings and resulted in a FERC-approved tariff change that allows hydroelectric and energy storage resources to bid above the ISO’s $1,000/MWh soft offer cap. (See FERC Approves CAISO Request to Lift Soft Offer Cap for Hydro, Storage.)

Scarcity Pricing

Scarcity pricing, a mechanism to determine market prices when supply falls short of demand, came into focus for CAISO following grid emergencies during the summers of 2020, 2022 and 2023, Friedrich said.

The increased risk that comes with declining reserves and a rising loss-of-load expectation should translate into the market’s willingness to pay more for additional reserves to maintain reliability. And while the ISO already relies on a number of different scarcity pricing mechanisms — including the scarcity reserve demand curve, the flexible ramping product and bidding above the soft offer cap — ISO staff and stakeholders saw a need to improve on those mechanisms to ensure more efficient market outcomes and maintain grid reliability.

“It’s important to note that while these mechanisms provide a good foundation for scarcity pricing in our markets, this initiative considers potential enhancements to ensure that they accurately reflect scarcity conditions across the entire market footprint and across all market intervals,” Friedrich said.

Staff and stakeholders have identified four key issues around scarcity pricing.

First, the market is inconsistent in how it procures ancillary services, a function not applicable to the WEIM or EDAM. The real-time market only procures incremental ancillary services for the CAISO balancing authority area (BAA), rather than fully re-optimizing them, Friedrich said. The market also doesn’t re-optimize in the five-minute market, leading to less efficient scarcity pricing outcomes and procurement.

Second, prior working groups also identified potentially outdated penalty prices, which currently are tied to the market bid cap and may not accurately reflect the true reliability value of a resource during scarcity events, Friedrich explained. Stakeholders also expressed concern the prices may be too low to provide effective incentives.

The third issue relates to potential disconnects between market prices and grid conditions during emergencies. The current market design may not adequately reflect the severity of emergency conditions in market prices, Friedrich said, leading to situations in which prices don’t align with the actual scarcity level indicated by emergency operator actions.

The last problem centers around insufficient scarcity signals. The scarcity reserve demand curve and power balance constraint violations in the market only get triggered during actual shortages, Friedrich said, which can result in price spikes that are “volatile and unpredictable.”

“Collectively, these issues point to the need for reform of our scarcity pricing mechanism, and by addressing these problems we aim to improve market efficiency, enhance reliability and provide more accurate price signals that reflect real-time grid conditions,” Friedrich said.

Elaborating on the initiative’s main objectives, Friedrich highlighted three main goals:

    • to improve market signals during tight supply conditions so that prices accurately reflect the true state of the grid;
    • to incentivize resource performance and demand reduction; and
    • to align prices with real-time grid conditions across the WEIM.

But two significant hurdles stand in the way of achieving these goals, Friedrich said. The first is the need to address discrepancies in how scarcity pricing applies across different balancing authorities in the market, while the second is the need to identify a “consensus-driven method to scale and anchor penalty prices.”

Market Power Mitigation

Friedrich said CAISO also must change rules around market power mitigation, which prevents the exercise of structural market power when a BAA is price-separated from CAISO.

Three main problems were identified in prior working groups: structural market power may be overestimated in individual BAAs; the CAISO BAA is excluded from the market power mitigation test; and the frequent mitigation during off-peak hours with low prices raises questions about current triggers.

The top priority is to ensure competitive pricing while refining mitigation mechanisms for WEIM and Extended-Day Ahead Market (EDAM) BAAs.

Fast-start Pricing

Friedrich also gave an overview of fast-start pricing, which integrates commitment costs of fast-start resources into market prices.

“Fast-start pricing recognizes that fast-start resources may serve as the marginal resource used to meet the next increment of energy or operating reserves demand,” Friedrich’s presentation said. “However, they often have output levels that prevent them from being fully dispatchable and thus are often ineligible to set the LMP.”

Phase 1 included a stakeholder-requested analysis to determine the potential market impact of fast-start pricing and whether it should be implemented. The analysis demonstrated a “generally moderate” impact, and some stakeholders saw value in continuing to prioritize the topic in discussion, while others didn’t. While members of the working group haven’t reached consensus, they mostly supported a deeper analysis of fast-start pricing.

Supporters of SPP’s Markets+ have pointed to the absence of fast-start pricing as a shortcoming of the EDAM.

The working group’s next Phase 2 meeting is tentatively scheduled for Oct. 23, and the target date for a straw proposal is May 25, 2025.

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FERC Rejects Mabee’s 2021 Supply Chain Complaint

FERC on Oct. 1 rejected a three-year-old complaint by security gadfly Michael Mabee requesting the commission order an audit of the electric grid looking for potentially harmful equipment manufactured in China and reliability standards requiring any new Chinese equipment to be tested for harmful capabilities (EL21-99). 

Mabee filed his complaint in August 2021, citing contemporary reports from media outlets and government officials that China had conducted “a campaign of cyberattacks” against critical U.S. infrastructure, including the energy sector. Specifically, he warned that U.S. electric utilities bought equipment made in China and installed it on the grid. 

This “could facilitate a cyberattack” by the Chinese government, Mabee asserted, particularly because — as he said — there were no requirements by the U.S. government or in NERC’s standards that entities inspect Chinese equipment for cyber risks and vulnerabilities either before or after installation. 

To address these supposed risks, Mabee requested the commission direct NERC to: 

    • survey all registered entities in the electric grid to find out “what Chinese equipment or systems” are in use; 
    • submit a proposed reliability standard for “testing and security of Chinese equipment or systems” that are in use on the bulk power system or purchased in the future; and 
    • work with state regulators to encourage adoption of the proposed standard or a state equivalent on the parts of the grid under state jurisdiction. 

NERC responded to Mabee’s complaint in 2021, arguing that FERC should deny his request on the grounds that several existing Critical Infrastructure Protection (CIP) standards already required entities to assess risks to the grid when acquiring applicable electronic systems. The ERO said that if the CIP standards identified a specific foreign nation by name, as Mabee requested, it might be harder to apply them to “other nation-states that may pose a threat.” (See “NERC Argues to Dismiss Supply Chain Complaint,” NERC Seeks FERC Approval to Fund Office Move.) 

Other commenters were more sympathetic to Mabee, FERC noted in its order. The Secure the Grid Coalition — a security-focused think tank to whose website Mabee has contributed several articles — suggested FERC conduct a technical conference, possibly in conjunction with a special task force, to “determine the potential threat posed [to the grid] by Chinese transformers and other grid control and monitoring systems.” 

The Foundation for Resilient Societies — a nonprofit aimed at “boosting critical infrastructure resilience and recoverability” — also requested that FERC, NERC and other agencies conduct an investigation into the threat posed by Chinese equipment. In addition, several individuals filed comments expressing support for Mabee’s position and urging the commission to take the threat of Chinese infiltration into the power grid seriously. 

Mabee himself has followed up his original complaint with multiple subsequent filings prodding FERC to take action. His most recent filing was this February, when he submitted data from the Census Bureau purportedly showing the U.S. imported 449 transformers of more than 10,000 kVA from China between 2006 and 2023. 

FERC Sides with NERC

FERC agreed with NERC that “the relief sought [by Mabee] is duplicative of existing reliability standards, as well as past and ongoing efforts by the commission and other federal agencies.” 

In addressing Mabee’s request for an audit of electric utilities for Chinese equipment, FERC observed that NERC can “assess the risks associated with foreign owned suppliers” through existing means such as NERC Alerts. It cited two such alerts, issued in 2019 and 2020, requesting information from registered entities on exposure to cyber risks from equipment manufactured in China, Russia and other foreign adversaries. 

FERC also sided with NERC in its defense of the CIP standards, and noted its own activities, along with other federal agencies, to address the risks posed by equipment manufactured overseas. Since Mabee’s complaint, FERC has held two technical conferences in 2021 and 2022 covering cyber risk management in the power sector and supply chain security challenges in the power grid. 

Concerns over China’s cyber prowess in recent years have focused more on its capabilities in software than in hardware. Last year Volt Typhoon, a cyber actor connected to China by the Cybersecurity and Infrastructure Security Agency and other security organizations, was accused of infiltrating U.S. critical infrastructure organizations disguised as legitimate users. 

In a congressional hearing this year, FBI Director Christopher Wray called China’s cyber posture “the defining threat of our generation” and warned that the country’s hackers were preparing “to wreak havoc and cause real-world harm to American citizens and communities.” (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.) 

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OSW Industry, Advocates See Hope in NE Multistate Procurement

Even as the offshore wind industry continues to struggle, stakeholders’ hopes have been buoyed by the recent multistate procurement in New England, they said during a webinar held by the Northeast Energy and Commerce Association on Oct. 1. 

Massachusetts selected up to 2,678 MW of offshore wind capacity in early September, while Rhode Island selected 200 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) 

“I think Massachusetts was pretty bold in doing procurements of this size, and I think that’s going to help get offshore wind back on track,” said Ken Kimmell, chief development officer at Avangrid Renewables. 

Kimmell said he is “starting to see the ship righting itself” in the wake of the price shocks that caused a wave of project cancellations in 2023. 

Massachusetts and Connecticut are in talks for Connecticut to purchase the remaining 400 MW of the Vineyard Wind 2 project in exchange for Massachusetts purchasing some power from the Millstone nuclear plant, which currently is propped up by a contract with Connecticut. 

The rapidly increasing costs of offshore wind have caused some trepidation from New England lawmakers; the 2,678 MW selected in the multistate procurement fell significantly short of the 6,000 MW initially sought by the three states. 

While the prices for the procurement will not be announced until the contracts are filed with state utility regulators, the cost of offshore wind per megawatt-hour has roughly doubled in just a few years. 

“The last couple years have been hard for the offshore wind industry … but I think the future is bright,” said Moira Cyphers, director of Atlantic offshore and eastern state affairs at the American Clean Power Association. “This is a resource that we absolutely have to have. The climate goals and the reliability goals don’t happen without offshore wind.” 

Despite the current cost pressures, Cyphers said procuring projects at scale “is really what’s going to bring down costs over time.” 

Cyphers added that the first line of projects will shoulder costs associated with building up the domestic supply infrastructure, ports and shipping capabilities, which “future projects will then build on.” 

Kimmell echoed the need to improve the domestic supply chain and added that increasing global demand for offshore wind has exacerbated the recent cost increases. 

“Supply and demand are out of whack,” Kimmell said. “We are at a real disadvantage relying so much on European suppliers.” 

Kimmell also voiced his support for longer contracts for offshore wind resources. 

“It [would] reduce prices to ratepayers if Massachusetts were to extend the length of contracts,” Kimmell said, noting that the current generation of turbines will last “quite a bit longer than 20 years.” 

Cyphers said more flexibility regarding economic adjustment mechanisms could help improve future solicitations. 

“I think flexibility is going to become a lot more important at this stage in development,” Cyphers said, noting that Connecticut, Massachusetts and Rhode Island each took slightly different approaches to the inflation indexation options they gave to developers. Ultimately, no indexed project bids were selected. 

“I think to the extent that we can work to identify other ways to introduce flexibility, and make sure these procurements become more standardized, we’ll see more success in the future,” Cyphers said. 

Ben D’Antonio, manager of transmission strategy and economic analysis for Eversource Energy, stressed the need to develop transmission solutions to add “certainty and clarity” to the process of interconnecting offshore wind projects. 

He expressed hope that state-level efforts to reform permitting and siting procedures, coupled with FERC’s new interconnection requirements, eventually will help to speed up development timelines, which currently take about a decade for offshore wind projects. 

While developers have limited insight on where the best places to interconnect are, D’Antonio advocated for a more proactive transmission development approach. He floated the idea of charging a fixed fee for projects to interconnect so developers could “know ahead of time what it’s going to cost to interconnect.” 

“We want to try out this ‘build it and they will come’ approach,” D’Antonio added. “There’s no transition without transmission.” 

This year, FERC approved a proposal from ISO-NE and the New England states that would enable the states to make transmission investments to meet long-term needs, including needs associated with new offshore wind generation. (See FERC Approves New Pathway for New England Transmission Projects.) The six New England states also recently won a $389 million Department of Energy grant that largely will be dedicated to building substations to connect offshore wind to the grid. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

Kimmell echoed D’Antonio’s comments about the need for proactive transmission planning, saying a line-by-line approach to transmission solutions makes sense for the initial projects coming online, but not for the next wave. 

“We certainly embrace the idea of shared transmission and planned transmission,” Kimmell said, advocating for the socialization of some of the costs associated with building transmission for offshore wind. 

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Re-ballot Underway for IBR Ride-through Standard

[Editor’s note: A previous version of this article incorrectly stated that PRC-029-1, addressing IBR frequency and voltage ride-through requirements, passed a ballot round that concluded earlier this week. The standard that passed that ballot round was actually PRC-024-4 (Frequency and voltage protection settings for synchronous generators, type 1 and type 2 wind resources, and synchronous condensers). PRC-029-1 is undergoing a re-ballot that will end Oct. 4 at 8 p.m. ET. The text below has been updated to reflect this.]

NERC’s proposed reliability standard addressing ride-through protection for inverter-based resources (IBRs) is undergoing a re-ballot in hopes of gaining enough industry support for passage, as the ERO’s Board of Trustees prepares to meet next week to formally adopt the five proposed IBR standards needed to meet a FERC deadline.

The ballot for PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) was originally scheduled to end on Sept. 30 but was extended to Oct. 4 to allow industry more time to review revisions, summarized in a memo on the project’s NERC webpage.

A ballot for the standard’s implementation plan will also close Oct. 4. The implementation plan also covers PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers), which was developed by the same drafting team as the ride-through standard.

PRC-024-4 did close its final ballot round Sept. 30, with industry stakeholders, voting by segment, casting 184 votes in favor of the standard, compared with 34 negative votes with comments, while 53 members of the ballot body either abstained or didn’t cast a vote. NERC weights its standards voting by segment participation so that industry segments with fewer voters will count less in the final tally. Therefore, the final segment-weighted value is 86.41% in favor, well over both the two-thirds majority needed for approval.

At its August meeting, NERC’s board exercised for the first time its authority to streamline the ERO’s regular stakeholder approval process, after PRC-029-1 did not receive industry approval after multiple ballot rounds. Board Chair Kenneth DeFontes warned this put the ERO in danger of failing to meet FERC’s deadline, imposed last year, to submit reliability standards addressing IBR performance requirements, disturbance monitoring data sharing and post-event performance validation by Nov. 4, 2024. (See NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.)

The board ordered NERC’s Standards Committee to convene a technical conference to receive input from industry and other ERO stakeholders on the ride-through standard in order to shape a version palatable to enough ballot body members to get across the finish line. At the conference, which was held Sept. 4-5 in D.C., representatives from a range of industry segments — including NERC, original equipment manufacturers and utilities — discussed their issues with the proposed standard. (See NERC, Industry Discuss IBR Issues in Technical Conference.)

After the conference, NERC revised the standard to address attendees’ concerns, including the clarity of the definition of “ride-through,” criteria for frequency ride-through performance and exemptions to ride-through criteria for equipment with hardware limits.

If it passes this ballot round, PRC-029-1 will not be posted for the customary final ballot, another result of the streamlined process approved at the August board meeting. At their meeting Oct. 8, trustees will vote on PRC-029-1 and PRC-024-4, along with the other IBR standards that are subject to FERC’s November deadline and were approved in previous ballot rounds:

    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.
    • PRC-002-5 — Disturbance monitoring and reporting requirements.
    • PRC-030-1 — Unexpected inverter-based resource event mitigation.

If PRC-029-1 does not receive a two-thirds segment-weighted vote in favor, the board may still consider it approved if it receives at least 60% of the vote. In that case, the board must solicit written public comment on the proposed standard and may convene an additional technical conference. If the board is satisfied that the standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest, it may then file the standard with FERC for approval.

In the event that the standard does not receive at least a 60% segment-weighted majority, the board has other options available, including directing the Standards Committee or NERC management to prepare another draft standard, convening another technical conference, and approving the standard after a 45-day public comment period but without a formal ballot.

Also on the board’s agenda next week are revisions to the charter of NERC’s Reliability and Security Technical Committee (RSTC) that are intended to improve the balance of industry representation at meetings. The new rules will allow a sector to seek a special election to fill an open seat representing it, rather than have that seat convert to an at-large member as the current charter provides.

In addition, they will remove the numerical cap on the number of representatives from a sector that can serve as at-large members and will direct the RSTC Nominating Subcommittee to prioritize balanced sector representation.

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Exelon Asks FERC to Weigh in on Co-location Dispute with Constellation

Exelon on Sept. 30 filed a petition for a declaratory order from FERC on its dispute with Constellation Energy over the latter’s effort to co-locate major loads at two of its nuclear plants (EL24-149).

The two firms, which used to be one before Exelon spun off its generation and competitive retail businesses into Constellation, have been on opposite sides of the debate on co-location from a purely policy level. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

But Exelon’s petition lays out the actual business dispute. Constellation is seeking to co-locate new loads at its Calvert Cliffs Nuclear Power Plant in Maryland and Limerick Nuclear Power Plant in Pennsylvania. Those plants are connected to the grid owned by Exelon’s Baltimore Gas & Electric (BGE) and PECO Energy utilities, respectively.

Neither the petition, nor the legal correspondence filed alongside it, mention data centers specifically with the modifications. But Exelon argued that Constellation’s moves could harm new and existing customers, including data centers. The economics of co-locating data centers at nuclear plants are lucrative, as a deal with Microsoft was enough to get Constellation to reopen the recently retired unit at Three Mile Island, Exelon said.

“Constellation has wrongly claimed that the existing interconnection agreements between the petitioning utilities and predecessors of Constellation (and, in the case of Calvert, PJM) entitle it to connect new end-use load without regard to the purpose and terms of the existing interconnection agreements or to the retail nature of the interconnection and requested services involved,” Exelon said in its petition.

Exelon wants FERC to find that PJM’s generator interconnection procedures under Order 2003 only apply to end-use generation, not load. FERC also should declare that interconnection of end-use load is a matter of state, not federal jurisdiction, the company argued.

Under the Federal Power Act, FERC is required to respect states’ role to regulate retail rates, Exelon said. Order 2003 itself was aimed at ensuring fair competition for generation, and FERC should make clear that it does not apply to end-use customers, it argued.

Exelon also asked FERC to find that a request to reconfigure existing generator interconnections to accommodate the co-located large, new loads would require modification of the relevant interconnection agreements to reflect the new interconnection facilities and the changed nature and purpose of the interconnection. That requires the consent of all the parties to such deals, the company argued, urging FERC to declare that as well.

The company said it supports the efforts of retail customers who chose to co-locate at generators when that can be accomplished safely and reliably and when load pays for its fair share of the costs of the electric grid, as defined by the applicable state and federal rates.

“Fortunately, the standard process of adding end-use load to the system is well understood and can be accomplished quickly while protecting system reliability and other customers,” Exelon said. “That process requires only that the load becomes a retail customer of the relevant distribution utility or cooperative, pay rates under existing tariffs, and that the interconnection be studied for safety and reliably.”

Changing the interconnection agreements to include large new loads transforms such deals into three-legged arrangements connecting end-use load, generation and the grid, which is significantly different from plugging a generator on its own to the grid, Exelon said.

Both BGE and PECO received requests for such co-locations, and they asked questions that would reflect the standard process for load additions, in which the customer itself or its agent asks the local distribution utility for service and describes the nature of the load and other factors.

Constellation took exception to those requests, saying the two utilities were not allowed to “condition performance of [interconnection agreement] obligations,” Exelon said. Constellation argued it was not required to arrange for retail service for the co-located load deals it is pursuing, according to Exelon.

“By its plain terms, PJM’s tariff does not and could not contemplate interconnection of end-use load through the generation interconnection process,” Exelon said. “Moreover, in its letter concerning Calvert Cliffs, Constellation has also declared that it may resort to litigation or referrals, including supposed antitrust claims, if BGE does not immediately take steps to provide the service Constellation requests.”

The controversy reflects a fundamental disagreement on the law, which includes foundational principles of jurisdiction, in the context of matters of serious import, Exelon argued.

It “respectfully request[ed] that the commission issue declarations that will settle this controversy, which threatens to cloud and undermine the jurisdictional and regulatory division between the states and the federal government embodied in the FPA, and which promises widespread, protracted litigation because requests to modify generator interconnections to accommodate co-located end-use load are becoming increasingly common,” Exelon told FERC. “By eliminating any confusion created by Constellation’s attempts to shift costs of co-located load at its generator interconnections, the commission can speed the energy transition, ensure reliability and protect all customers.”

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Newsom Signs Bundle of Grid-related Bills from 2024 Session

California Gov. Gavin Newsom has signed a bill to streamline approval of transmission projects by removing a requirement for regulators to evaluate non-transmission alternatives such as demand-side management. 

Assembly Bill 2292, by Assemblymember Cottie Petrie-Norris (D), is just one in a bevy of bills the governor signed into law in the days leading up to a Sept. 30 bill-signing deadline. Other new laws relate to bi-directional EV charging, industrial energy use and hydrogen fueling stations. 

Proponents of AB 2292 said the bill makes a modest but important change to the California Public Utilities Commission approval process for transmission projects.  

The bill removes a requirement for the CPUC to consider cost-effective alternatives to transmission facilities “that meet the need for an efficient, reliable and affordable supply of electricity.” Those alternatives may include demand-side options such as targeted energy efficiency or ultraclean distributed generation. 

Requiring the CPUC to review alternatives duplicates work done by CAISO in identifying the need for the project as part of its transmission planning process, supporters said. 

The new law comes as the CPUC is updating its General Order 131-D to make the permitting process for transmission projects more efficient and consistent. (See CPUC Works to Revamp Tx Permitting Rules.) 

Bi-directional Charging Bill

Another bill signed by Newsom could lead to a requirement for electric vehicles to be equipped for bi-directional charging. 

Senate Bill 59, by Sen. Nancy Skinner (D), authorizes the California Energy Commission (CEC) to require any size class of battery EV to be capable of bi-directional charging — if there is a “compelling beneficial” use case for both the EV operator and the electrical grid. 

“Bi-directional capabilities in BEVs have the potential to improve customer energy reliability, resiliency and demand management during electric grid stress events while supporting our state’s transition to zero-emission transportation,” Newsom said in a bill-signing message. 

The governor’s message noted the complexities of aligning BEVs with the bi-directional charging equipment, while factoring in electric rates and potential grid effects. 

Another Petrie-Norris bill signed by the governor is AB 2779, which promotes the use of grid-enhancing technologies. The bill requires CAISO to report any new use of GETs that it deems reasonable, along with the cost savings and efficiency of that technology, when it approves a transmission plan.  

GETs are a way to expand the capacity of the grid much more quickly than building new transmission, which can take years. They include advanced reconductoring and other technologies. 

The governor previously signed SB 1006, by Sen. Steve Padilla (D), which requires utilities to study the feasibility of using GETs. (See California GETs Bill Gets Newsom’s Signature.) 

RA Requirements

Another bill signed into law is Petrie-Norris’ AB 2368, which addresses electric system reliability. 

The bill, sponsored by the Clean Energy Buyers Association, requires the CPUC to adopt a 1-in-10 loss of load expectation (LOLE), or a “similarly robust reliability metric,” when setting resource adequacy requirements. (See Clean Energy Buyers Push Passage of New Calif. Reliability Law.) 

The bill also requires the CPUC to determine whether measures are needed to reduce the costs to ratepayers of a resource adequacy program. 

A bill sponsored by the California Nevada Cement Association also received Newsom’s signature. AB 2109, by Assemblymember Juan Carrillo (D), will exempt large industrial customers from paying their utility a departing load charge if they use waste heat to generate their own power. 

The bill will make industrial process heat recovery cost effective and advance the state’s efforts to decarbonize manufacturing, CNCA Executive Director Tom Tietz said in an opinion column. 

Hydrogen Fueling Stations

SB 1418 by Sen. Bob Archuleta (D), which the governor signed, is intended to speed up local government permitting of public hydrogen-fueling stations. 

Cities and counties are already required to streamline the permitting process for EV charging stations. SB 1418 will extend that streamlining by requiring cities and counties to adopt an ordinance and checklist for permitting hydrogen-fueling stations.  

Archuleta noted in a release that the Department of Energy has awarded up to $1.2 billion to California’s hydrogen hub, the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES). 

“Success hinges on rapidly scaling up hydrogen-fueling infrastructure and vehicle development,” the release said. “California cannot achieve its zero emission goals without success at the local level.” 

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FERC Approves CAISO Plan to Streamline Interconnection Process

FERC has approved CAISO’s proposal to streamline its generator interconnection process to deal with the “unprecedented volume” of interconnection requests it received in 2023, in part stemming from the aggressive push to decarbonize California’s economy.

The product of more than a year of stakeholder engagement, the Interconnection Process Enhancements (IPE) proposal was designed to speed up CAISO’s interconnection queue by reducing the number of projects the ISO must review in its queue cluster study process through use of a new screening procedure that prioritizes projects based on transmission availability and commercial viability. (See CAISO Board Approves Interconnection Enhancements Proposal.)

The IPE proposal approved Sept. 30 by FERC is intended to complement — and not replace — CAISO’s FERC Order 2023 compliance filing. The commission said the approval is subject to its action on the ISO’s Order 2023 compliance filing.

The IPE tariff revisions will apply to the ISO’s outsized interconnection Cluster 15 — from 2023 — and subsequent cluster periods.

“CAISO has demonstrated that applying the proposed revisions to Cluster 15 will enable CAISO to effectively process the largest queue cluster it has ever received,” the commission wrote in its 103-page order (ER24-2671).

A central aspect of the IPE proposal is adoption of a zonal approach that prioritizes interconnection of resources that use existing available transmission capacity in areas where capacity additions have been approved in the ISO’s transmission plan, as set out in state and local regulatory authority resource planning portfolios.

The zones are defined by available capacity based on transmission constraints and the California Public Utilities Commission’s resource planning portfolio. A zone containing at least 50 MW of available transmission capacity is defined as a transmission plan deliverability (TPD) zone. Generation projects seeking to interconnect outside TPD zones “may proceed as merchant projects and will self-fund their associated network upgrades” in those so-called “merchant zones,” according to the proposal.

The proposal also introduces scoring criteria that rank projects based on factors such as project readiness, load-serving entity interest and commercial — or non-LSE — interest.

Under that part of the process, LSEs will award points to projects based on a 1-to-100 scale, with the points representing the percentage of transmission capacity the LSEs would assign to the projects. Non-LSEs can award a maximum of 25 points, which CAISO attributed to the fact that LSEs must meet specific resource adequacy and procurement requirements while non-LSEs have no such obligations, although they might be serving a commercial interest.

“Notably, in evaluating commercial interest, the ISO will incorporate preliminary, non-binding feedback on specific projects from load-serving entities,” the proposal says. “In addition, the ISO provides an opportunity for non-LSE offtakers (e.g. commercial entities) to express an interest in specific projects. These commercial selections will improve the scores of certain projects, increasing the likelihood of those projects advancing to the study process and ultimately competing for transmission plan deliverability (TPD) and offtake agreements.”

The highest-ranking projects then advance to the study phase in descending order of project scores, until the available and planned transmission capacity within a zone (and behind constraints) is filled to 150% of that capacity. CAISO will resolve ties by selecting projects with the lowest distribution factors (DFAX). If a tie persists, the ISO “will conduct a market-clearing sealed-bid auction to advance to the study process that will align with the process required under FERC Order No. 2023,” according to the proposal.

‘Monitor the Efficacy’

In approving the IPE tariff rules, the commission said it found the revisions fulfill the purposes of FERC’s Order 2003 and Order 2023 rules on generator interconnection “by helping to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.”

FERC found the zonal aspect of the plan, which subgroups projects based on transmission deliverability, “links the CAISO interconnection process with the transmission planning process and resource planning process, ensuring that interconnection requests in zones with sufficient deliverability to serve them are prioritized, which will improve certainty for developers while addressing queue backlogs.”

The commission also rejected the arguments of protestors who called the proposal’s distinction between “merchant” and TPD zones discriminatory, determining the proposal’s process requiring interconnection customers outside TPD zones to self-fund network upgrades is consistent with FERC’s interconnect pricing policy.

“The commission has previously allowed RTOs or ISOs with locational pricing to require interconnection customers to bear the cost of all facilities and upgrades not needed but for the interconnection, stating that providing reimbursements or service credits for network upgrades that would not be needed but for the interconnection mutes the incentive for a customer to make an efficient siting decision that accounts for transmission costs,” it wrote.

FERC also dismissed the concerns of Shell and Vistra regarding the transparency of the zonal approach, finding CAISO’s plans to publish supplemental information on its website describing conditions and constraints in each transmission zone, along with the ISO’s “commitments to provide information about its zonal determinations, provides sufficient transparency to inform the preparation of interconnection requests under the proposed cluster study criteria.”

The commission further rejected the arguments of multiple protestors in accepting the proposal’s scoring criteria.

“Specifically, prioritizing those interconnection requests that are more advanced in their technical planning and design can help CAISO eliminate speculative interconnection requests and identify potential interconnection customers that have completed more of their project development in advance of the cluster request window, and are therefore more likely to reach commercial operation,” the commission wrote.

The commission said it still will evaluate CAISO’s compliance with each requirement in Order 2023 and that “nothing in this order prejudges the outcome of that evaluation.” It also noted CAISO’s commitment to “monitor the efficacy” of the IPE revisions and said it expects the ISO to continue to engage with stakeholders on “further enhancements to improve the interconnection process as needed.”

“Our tariff filing for a reformed interconnection process was complex and we fully acknowledge that stakeholders had a variety of opinions on some of the details,” CAISO CEO Elliot Mainzer said in a statement.

“We appreciate the ruling by FERC and what it will mean for more efficient planning and onboarding of resources, and we are committed to moving forward in partnership with our many stakeholders to effectively and transparently implement the reforms. As the order requires, we will also closely monitor how well they are working,” Mainzer said.

The new rules became effective Oct. 1.

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Eversource Takes Another Financial Hit with OSW Exit

Eversource Energy has formally ended its costly foray into offshore wind development, finalizing the sale of its last two offshore assets and predicting a half-billion-dollar loss as a result. 

The utility announced Sept. 30 that Global Infrastructure Partners (GIP) had closed on its purchase of Eversource’s share of South Fork Wind and Revolution Wind, which respectively completed and started construction this year off the Rhode Island/Massachusetts coast. 

When the deal was announced in February, Eversource said it expected to receive $1.1 billion as a result. It said Sept. 30 that adjusted gross proceeds instead will be $745 million because of higher-than-expected costs associated with South Fork and Revolution. 

Eversource said it anticipates other factors to cause it to record a net loss of approximately $520 million on the divestiture. 

The company previously recorded a $1.95 billion after-tax impairment for 2023, also because of the struggles of its offshore wind venture. (See Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023.) 

Eversource had been looking for an exit at least as far back as 2022, when the offshore wind industry began to slide into a financial crisis in the U.S. It will remain involved with offshore wind, but only in the onshore transmission that interconnects the projects. 

CEO Joe Nolan hailed the company’s success in refocusing as a “pure-play regulated pipes and wires utility.” 

“We are proud of the role we have played to advance offshore wind projects,” he said, “and we will continue to be a leader in employing our transmission expertise to conduct onshore work that supports the clean energy transition and enables the continued development of renewable resources for our region.” 

Eversource, New England’s largest distribution utility, and Ørsted, the world’s leading offshore wind developer, teamed up in December 2016 in a 50-50 venture to enter the nascent U.S. offshore wind market. 

Their efforts progressed steadily, but not quickly enough to beat the combination of rising costs and supply chain constraints that led to the 2023-2024 cancellation of most of the first wave of offtake contracts signed for wind farms proposed off the Northeast coast. 

The companies did complete South Fork, the first operational utility-scale wind farm in U.S. waters, but it is only 12 turbines rated at a combined 132 MW — just 0.44% of President Joe Biden’s goal of 30 GW by 2030. And it cost more than expected. 

Eversource has been chipping away steadily at its ownership share in the joint venture, selling Ørsted its share of an undeveloped wind lease area and the Sunrise Wind project. The latter netted Eversource approximately $370 million, lowering the anticipated loss associated with its offshore wind divestiture from nearly $900 million to a bit more than $500 million. 

Ørsted said in a news release that it was excited to team up again with GIP, “a trusted and longstanding” partner worldwide. GIP is now a component company of BlackRock, which announced Oct. 1 that it had completed the acquisition. Skyborn Renewables, a GIP portfolio company, will manage ownership of the 50% stake in South Fork and Revolution. 

“Partnering on the Revolution Wind and South Fork Wind projects marks a significant step in expanding Skyborn’s presence in the U.S. offshore wind market,” Skyborn CEO Patrick Lammers said in a news release. “Moreover, this joint venture with Ørsted perfectly exemplifies our successful partnership model. This transaction offers strong value potential for our shareholders and partners through a well-structured approach that carefully mitigates key risks.” 

Eversource indicated in a Feb. 13 filing with the Securities and Exchange Commission that it had guaranteed GIP a 13% pre-tax, equity internal rate of return as part of the sale agreement. It also agreed to cover increases in construction costs for Revolution. 

The company’s Sept. 30 SEC filing detailed $890 million in costs it has incurred under terms of its agreement with GIP: approximately $225 million in non-construction costs for South Fork and Revolution, $315 million in post-closing adjustments for Revolution and South Fork, and $350 million in higher construction costs for Revolution because of the previously announced pushback of its expected commercial operations date. (See Revolution, Sunrise OSW Projects Face New Delays.)

That is separate from the factors that reduced Eversource’s adjusted gross proceeds from the sale of Revolution and South Fork from $1.12 billion to $745 million: approximately $150 million in capital spending that did not take place as expected and approximately $225 million because of the delays with Revolution. 

Eversource said other factors still could decrease — or increase — its net proceeds from the sale: Revolution’s eligibility for 40% tax credits, the ultimate cost of construction for Revolution, further delays in construction of Revolution, and lower operation costs or higher availability of Revolution and South Fork. 

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Helene Repair Efforts Could Last Weeks for Hardest Hit, Remote Areas

The utility industry continues to repair downed power lines and other infrastructure affected by Hurricane Helene. Much of the remaining work is on co-ops’ systems, according to the National Rural Electric Cooperative Association.

“Electric cooperatives serve the most remote, hardest to serve areas in the country, and so while this disaster affected all utilities and customers in many different utility locations, the consumers of electric cooperatives are in areas that are more remote, more rugged, more difficult to restore,” NRECA CEO Jim Matheson said Oct. 1.

The storm knocked out power to about 6 million customers across 10 states, of whom cooperatives serve 1.25 million, he added. As of Tuesday afternoon, cooperatives still had about 500,000 customers without power. Most of those should get their lights back by the end of the week.

“This could have a long tail to it, in terms of when you reach everyone getting power back on,” Matheson said. “This could take days. This could take weeks, in some cases, because of the location and the amount of damage and what it’s going to take to essentially not just hook something up that happened to break apart, but really rebuild from the ground up, some of these components of the electric system.”

Tri-County Electric Co-op of Florida serves some of the area first affected by the storm. At its peak, 99% of its meters were offline on a system that averages six meters per mile of wire, largely residential and agricultural customers, said CEO Julius Hackett.

“We’re dealing with 700-plus broken poles,” he added. “We still have 12,300 meters out. But we have 2,000 line-workers and vegetation management professionals on the scene.”

The restoration has been progressing well, but it is slower than the co-op would prefer due to the Category 4 hurricane winds that significantly damaged its system, said Hackett.

The storm knocked out an additional 350,000 customers at co-ops in Georgia, said Dennis Chastain, CEO of the Georgia Electric Membership Corp., which represents all the co-ops in the state.

“I’ve been in this business for 38 years, and I’ve never seen anything like it,” Chastain said. “I’ve got one of my vice presidents who’s been here 50 years, and he’s an ex-lineman, and he’s never seen anything like it either.”

Electric Cooperatives of South Carolina CEO Mike Couick agreed Helene’s impact on the system was unlike any storm his members have dealt with in decades.

“It’s not a restoration, it’s a rebuild,” he added. “Every one of my co-ops in this state were affected. It affected all 46 counties.”

Particularly hard hit was the Blue Ridge Electric Co-op, named for the mountain range that runs through its territory, where line workers must repair 7,300 miles of wires, including lines that run straight up mountainsides.

“When we talk about putting a new power pole in because one’s broken, we generally say it takes four men up to four hours to put in one pole,” Couick said. “I’m not sure that’s the right number at Blue Ridge. Think about going up the side of a mountain, putting in a new pole, and you’re going to drill through a rock and sink it. You may not have access to roads to get the pole there, and then you gotta carry it there.”

Blue Ridge thinks it has about 600 broken poles to fix, but it cannot be sure this early in the process as accessing some of the more remote parts of its system is difficult, he added.

Western North Carolina was among the hardest hit regions by Helene where the issue is not just fixing the grid but washed-out roads and homes that were swept away by the storm and related flooding, said EnergyUnited CEO Thomas Golden.

“Mudslides, flooding and downed trees have made entire communities inaccessible,” he added. “Crews can’t even reach some members because roads have been washed away or blocked by debris. And when they do get through, they’re not finding a few downed lines, they’re finding entire spans of wire pulled down by trees, poles snapped in half and infrastructure washed away by floodwaters.”

So far, cooperatives have found enough material to make the repairs, but NRECA’s Matheson said supply issues must be monitored due to the widespread damage across all kinds of utility ownership.

“We need to keep an eye on this, because we very well could have supply chain challenges emerge in the next few days that we haven’t seen,” Matheson said. “The good news is, so far, I haven’t heard of any significant supply chain challenge.”

Two of the hardest-hit investor-owned utilities provided updates Oct. 1 on their progress repairing Helene’s damage.

Georgia Power said it had restored service to 1 million customers, which is about 80% of those affected, but additional 278,000 remained without service. The utility said Helene damaged or destroyed 8,000 poles, 1,000 miles of wire, 1,500 transformers and led to 3,200 trees falling on lines.

Duke Energy Carolinas reported it had restored power to 566,000 customers in South Carolina and 1 million in North Carolina with 363,000 and 284,000 remaining without service, respectively. Power restoration may take longer in areas that are inaccessible due to hurricane damage to other infrastructure.

“We’ve never seen such widespread devastation and destruction as we’re seeing in this region,” Jason Hollifield, Duke Energy storm director for the Carolinas, said in a statement.