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November 1, 2024

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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.

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Waiting for 45V, US Green Hydrogen Projects Frozen

WASHINGTON — A panel on hydrogen at the National Clean Energy Week Policymakers Symposium provided a state-of-the-industry update, looking at cutting-edge projects underway and the reluctance of developers and investors to move ahead as they wait for the Treasury Department’s final rule on the Inflation Reduction Act’s 45V tax credit. 

The world’s smallest molecule is widely being promoted as a potentially clean alternative fuel that can be used in hard-to-abate sectors, such as long-haul trucking or maritime shipping, or for long-duration storage. Hydrogen traditionally has been produced using natural gas as a feedstock, called blue hydrogen. But green hydrogen is produced by electrolysis ― splitting water molecules into oxygen and hydrogen ― powered by renewable energy.  

Chevron has a long history of producing blue hydrogen but has become bullish on green as a sector where the company “can leverage our assets and capabilities and relationships to really drive forward the energy transition,” said Michael Hoban, vice president for policy and government engagement at Chevon New Energies. “Our focus is lowering the carbon intensity of our own operations, as well as creating low-carbon businesses … where we think Chevron can add value.” 

Speaking at the Sept. 26 panel, Hoban pointed to Chevron’s Advanced Clean Energy Storage (ACES) project in Utah, which will produce green hydrogen from “about 220 MW of electrolyzers, storing about 100 tons per day of hydrogen [in] massive underground salt caverns … as a long-term energy [storage] solution.” 

Beau Berthelot, vice president of business development and government affairs at Maritime Partners, a maritime leasing and financing firm, said his company is building a hydrogen-fueled vessel, which will extract hydrogen from methanol, also called methyl alcohol. 

The new ship “will load methanol, convert the methanol into hydrogen, then fuel the vessel with hydrogen fuel cells,” Berthelot said. 

But Treasury’s delay on the 45V production tax credit ― which could be worth up to $3 per kilogram of green hydrogen ― has frozen the market, said Paul Wilkins, vice president for policy and government engagement at Electric Hydrogen, which manufactures electrolyzers used to produce green hydrogen. 

Treasury issued a proposed rule for 45V in December but has yet to issue a final rule. The department announced Oct. 1 that it intends to complete the final rule by the end of the year. (See Biden Admin. Issues Proposed Rules for Hydrogen Tax Credits.) 

“Project developers can’t get to a final investment decision if they don’t know what their revenue streams look like,” Wilkins said. “And so what that means is that projects are just churning water and burning through cash … not moving forward.” 

The U.S. has only about 150 MW of operating electrolyzers, a capacity he described as “tiny.” To bring down costs, “we really need to start scaling the industry.” 

The Department of Energy’s seven regional hydrogen hubs, funded with $7 billion from the Infrastructure Investment and Jobs Act, also have had a slow rollout. The law requires the hubs to be geographically and technologically diverse, producing hydrogen from natural gas with carbon capture as well as electrolysis powered by renewables. 

But one year after the seven hubs were announced, only three have finalized contracts with DOE.  

Chevron is involved in two of the hubs, one on the Gulf Coast (still in contract negotiations) and one in California (contract finalized), Hoban said. With or without clarity on 45V, coordinating all the facets and stakeholders is difficult, he said. 

“Hydrogen is a really difficult market to initialize for a lot of reasons,” he said. “Everything really has to happen at once. You can’t just simply make a supply project, and when it goes to the liquid market, you can’t simply buy a hydrogen fuel-cell truck. … The entire value chain needs to be coordinated together.” 

Permitting reform also will be critical, Wilkins said, to ensure dedicated pipelines for hydrogen can be built. “That’s going to be the cheapest way to move those molecules,” he said.  

Wilkins expects some projects, like the hubs, will co-locate the production of green hydrogen with its end uses. But “if you look at the places where you just make green hydrogen because you’ve got really cheap electricity, you’re going to have to move it,” he said. “We have to be able to build pipelines.” 

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PUC’s Gleeson at Texas Clean Energy Summit: Smooth Tenure Turns ‘Interesting’

SAN ANTONIO — Thomas Gleeson, chair of Texas’ Public Utility Commission, has seen it all during his tenure at the PUC.

Named the commission’s executive director in 2021 about a month before a winter storm nearly collapsed the ERCOT grid, Gleeson saw the commissioners whittled in numbers from three to two, then one and finally none as they each resigned under withering criticism in the storm’s aftermath. The commissioners’ numbers have grown to five since then due to legislation passed after storm, with Gleeson appointed as chair in January.

Everything went smoothly for Gleeson and the PUC until Hurricane Beryl caught CenterPoint Energy off-guard in July and then an apparently fraudulent generation project was temporarily included in a grant program for $5 billion in state funds. (See CenterPoint Energy Still in Eye of the Storm and Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.)

Dealing with the fallout of those two events has been added to the commission’s full plate, which includes finishing a market redesign and working to approve enough transmission to meet Texas’ growing industrial demand and deciding whether to use 765-kV facilities in that effort.

“The timeline of my time at the PUC has been quite interesting,” Gleeson told attendees during Infocast’s Texas Clean Energy summit, held Sept. 24-26.

“Transmission in this state is something that we haven’t talked a lot about in recent history, because we’ve been focused on market design,” he said. “I tell the governor and the other elected officials, ‘If you want this state to continue to be the economic center for the country and for the globe, you have to invest in infrastructure, water infrastructure, health communication infrastructure, electric infrastructure.’ Those things have to be done congruently, because you cannot have one without the other.”

Gleeson said demand is increasing in Texas because data centers and crypto miners are being added to the industrial base. ERCOT said earlier this year it expects an additional 150 GW of load by 2030, although not all eventually will be interconnected.

“So, what does that mean? It means a lot of companies, a lot of businesses plan to move here,” Gleeson said, noting some of that is crypto mining that “may show up or may not show up.”

“The load growth is something no other ISO in this country is seeing,” he said. “You hear a lot about the size of our state … so people automatically assume load growth is happening because people are moving within ERCOT. That’s not the truth … load growth on the residential side actually remains really flat. The increase in load is because of commercial and industrial customers coming here.

“That causes its own set of challenges, right?” Gleeson added. “You have residential customers that are paying a lot of the transmission costs, and those transmission costs are caused by non-residential customers, so I think that’ll be another story.”

Until then, Gleeson argues, Texas needs an energy expansion, not an energy transition.

“In this state with our load growth, you need an energy expansion,” he said, nodding to a slide that included ERCOT’s current fuel mix. “These percentages are not nearly as important to me as the underlying data, the total megawatts. I want more of all this to last the summer. If you look and analyze ERCOT data, you’ll see that on multiple occasions, solar and batteries saved us. We also need more gas-fired generation because I have days that no one else sees where we are really thin.”

Market Participants Pan PCM

Several panelists panned the PUC’s proposed performance credit mechanism (PCM), which was selected from among five other potential market designs in 2023.

The PCM has been criticized as favorable to thermal generators. It would reward them with credits based on their performance during a determined number of scarcity hours. Those PCs must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

“There’s been a lot of discussion about who can participate in the PCM,” Black Mountain Energy Storage’s Kevin Hanson said. “I think it’s very important that it has to be technology neutral, that any resource that can deliver those obligations and needs should be able to participate.”

Gleeson

Emily Mullins, Lightsource | © RTO Insider LLC 

Bob Helton, Engie North America’s vice president of government and regulatory affairs, pointed out that an early analysis of the PCM included renewables.

“By taking the renewables out of there, it does increase the cost,” he said, agreeing the PCM needs to be technology neutral. He also urged patience because it could have a bearish effect on real-time energy pricing. “We don’t want to end up with a PCM market with a large percentage of revenue coming through there and overtaking the energy market as a revenue source. We’ve seen that in capacity markets and other markets,” he added.

“I think what’s been lost in a lot of the discussions about an energy-only market is that it functions via scarcity,” Lightsource’s Emily Mullins, on another panel, said. “Scarcity pricing is important because it signals to developers when, where and what type of resource they need to build. However, since Winter Storm Uri, what we’ve seen is there’s snipping at the edges of the energy only market. So, we’ve ended up in this interesting situation where, by name, we’re in an energy-only market, but we’re sort of riding the fence between an energy-only market and the capacity market.”

Gleeson, who was the PUC’s executive director when it approved the PCM, referred to the design as a “novel approach.” He said given that, the PCM should be placed on the back end of other market changes.

“My feeling is, and I think my colleagues share this feeling, is that we have a number of tools at our disposal,” he said. “We should try to see if we can meet our reliability goals with those tools before we look to implement something that’s new and novel and that we don’t really know how it interacts with the rest of our market.”

Texas Eyes More Nukes

Constellation Energy’s Casey Kelley, vice president of state government affairs in the South, appeared at the conference on the heels of his company’s announcement that it plans to re-open Three Mile Island’s Unit 1 — not the one involved in a 1979 partial nuclear meltdown — as part of a power purchase agreement with Microsoft. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

Shannon McGriff, executive director of The Energy Professionals Association and moderator of Kelley’s panel, said she was with the Constellation executive two days before the announcement.

“So, we know you can keep a secret,” she told Kelley.

“I think nuclear is going to be a big topic in Texas this time around, not because anybody’s going to build a new AP 1000 [plant] or even [small modular reactors] in the short term, but I do believe there will be conversation about how we set up the framework to make Texas a leader in that space,” Kelley said, looking ahead to 2025’s legislative session.

He has a supporter in Gleeson, who is waiting on a task force’s report on small modular reactors (SMRs) due at the end of the year. Texas leaders hope the work will position the state as a leader in nuclear energy. The state already hosts two nuclear plants and their four reactors; each plant has 5,000 MW of installed capacity.

“My feeling is if you care about net zero emissions and you care about reliability, you have to care about nuclear. I don’t think the math works for where people are trying to go [meeting future demand] without adding nuclear power,” Gleeson said. “I think increased nuclear has to be a part of our energy future to meet our demand.”

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Cardinal-Hickory Creek Line Fully Energized 13 Years After MISO Approval

Thirteen years after it was recommended by MISO, the controversial 102-mile, $655 million Cardinal-Hickory Creek line is completely in service. 

Co-owners ITC Midwest, American Transmission Co. and Dairyland Power Cooperative announced the completed 345-kV line was flowing power between the Hickory Creek Substation in Dubuque County, Iowa, and the Cardinal Substation in Middleton, Wis., as of Sept. 26. The developers originally anticipated a June 28 full in-service date. The eastern half of the line was energized months ahead of the western half in December 2023 as court battles played out. 

Cardinal-Hickory Creek was approved in 2011 as part of MISO’s multivalue project portfolio and earned a reputation as the most contentious of the 17-line collection. The line’s construction pitted usual environmental bedfellows — conservationists and renewable energy developers — against one another because the line crossed through the Upper Mississippi River Wildlife and Fish Refuge. For years, conservation groups — the National Wildlife Refuge Association, Driftless Area Land Conservancy and Wisconsin Wildlife Federation — argued that the river crossing would scar and fragment wildlife habitat and ruin floodplains. 

Cardinal-Hickory Creek’s final mile intersecting the refuge was tied up in litigation for months this year as the conservation groups lodged a final lawsuit to halt an ultimately successful land swap between the utilities and the U.S. Fish and Wildlife Service that traded more than 35 acres in Wisconsin for almost 20 acres of the refuge’s Iowa footprint. (See Cardinal-Hickory Creek Developers Appeal Injunction on Line’s Final Mile.) 

The trio of environmental groups argued that the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated federal laws when they approved permits and accepted the land exchange.  

In May, the Seventh U.S. Circuit Court of Appeals lifted a Wisconsin federal judge’s preliminary injunction issued in March, clearing the way for the final, mile-long connection. The three-judge panel said the federal judge lacked justification for his decision to grant the injunction. Conservation groups tried for a stay; Environmental Law and Policy Center Executive Director Howard Learner, representing the conservation groups, argued the refuge “should not be bulldozed before the conservation groups receive their long-delayed fair day in court.”  

Dairyland Power Cooperative CEO Brent Ridge characterized line completion as a “victory for energy consumers and the environment.”  

“As a backbone interconnection, the line will finally serve as the vital link to a long waiting list of regional renewable energy projects. While supporting carbon reduction goals, Cardinal-Hickory Creek also strengthens grid reliability and resilience at a time of great change in the energy industry,” Ridge said in a press release.  

“Following years of work, including numerous opportunities for public input, extensive regulatory and environmental review, and construction, the entire Cardinal-Hickory Creek line has been placed in service. This allows the project to begin providing numerous economic benefits for electric consumers and environmental benefits for the entire region,” ITC Midwest President Dusky Terry added. Terry thanked construction crews in particular for building the line “in full compliance with comprehensive environmental standards.” 

ATC Senior Vice President of Construction and Maintenance Jared Winters said Cardinal-Hickory Creek will improve reliability, allow access to lower cost energy and offer interconnection points for new renewable resources.  

ITC estimates that 160 renewable generation projects representing more than 24.5 GW in Wisconsin, Iowa and other parts of the Upper Midwestern states were dependent on the line’s completion.  

The developers said they minimized environmental impacts of construction as much as possible, consulting with federal agencies. They said they used wooden construction mats to reduce soil disturbance and sedimentation, did not perform any grading within the refuge and have restored or will restore any impacted natural areas.  

Clean Grid Alliance also cheered the announcement and said the line was subjected to “unsuccessful and unnecessary” legal challenges.  

“Finally! We can now celebrate the ability to deliver more than 24,000 megawatts of clean, affordable, reliable energy, plus the added benefit of improved grid reliability, all of which is now possible because the Cardinal-Hickory Creek transmission line has been energized,” Clean Grid Alliance Executive Director Beth Soholt said in a press release.  

Even with the line’s energization, the National Wildlife Refuge Association, Driftless Area Land Conservancy and Wisconsin Wildlife Federation remain hopeful in their lawsuit.  

Wendy Bloom, senior attorney at the Environmental Law and Policy Center, said a federal court has never found the crossing through the refuge legal. She said the conservation groups maintain ITC, ATC and Dairyland acted unlawfully by clearing protected refuge land after striking the land exchange. 

“Despite today’s news, we are still awaiting an important decision in our lawsuit in federal court. We are proud to have worked with so many in our community and other committed organizations to oppose construction of this unnecessary line,” Jennifer Filipiak, executive director of the Driftless Area Land Conservancy, said in a statement.  

The groups also said the east-west transmission line bisects a north-south migratory bird flyway used by hundreds of thousands of birds annually.  

Since its multivalue portfolio, MISO has designed two more long-term transmission portfolios: the first, $10 billion long-range transmission plan (LRTP) was approved in 2022, and MISO is advancing a second, nearly $22 billion LRTP package for board approval at the end of the year. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)  

The second LRTP portfolio calls for a 765-kV line crossing the Mississippi River from Wisconsin’s Driftless Area into Minnesota, which has led some members to call on MISO to keep the contested Cardinal-Hickory Creek in mind and carefully examine routing assumptions through protected areas. (See “LRTP Mississippi Crossing Raises Specter of Cardinal-Hickory Creek,” MISO Vouches for 2nd, $25B Long-range Tx Portfolio.)  

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FERC Approves $490K in Penalties for NERC Violations

PPL Electric Utilities will pay $400,000 to ReliabilityFirst for violations of NERC’s reliability standards, according to a settlement approved by FERC last week (NP24-12).  

The commission also approved a settlement between the Northeast Power Coordinating Council and Constellation Energy carrying a $90,000 penalty (NP24-11). 

NERC filed the PPL-ReliabilityFirst settlement in a notice of penalty on Aug. 29. FERC indicated in a Sept. 27 filing that it would not further review the settlement, leaving the penalty intact. 

The settlement stemmed from a violation of FAC-003-4 (Transmission vegetation management), which aims to establish “a defense-in-depth strategy to manage vegetation located on transmission rights of way … and minimize encroachments from vegetation located adjacent to the ROW.” Requirement R2 of the standard mandates that applicable transmission owners (TO) and generator owners (GO) “prevent encroachments into the MVCD [minimum vegetation clearance distance] of [their] applicable lines.” 

According to the agreement, PPL submitted a self-report in September 2023, indicating the utility had experienced a sustained outage the previous month. The outage, which lasted about 10 hours, was the result of a cherry tree that grew into the MVCD of a conductor loop on PPL’s Susquehanna-Wescosville 500-kV line. PPL said the line “tripped to lockout because of this vegetation encroachment.” 

ReliabilityFirst said the utility had not been “sufficiently modeling conductor loops located at transmission poles” in its transmission vegetation management program (TVMP). The TVMP used light detection and ranging data, along with foot patrols, to determine potential future vegetation issues, but PPL’s 3D model did not capture the conductor loops, leaving “blind spots” where vegetation growth was not monitored.

In the agreement, ReliabilityFirst observed that PPL’s violation “occurred nearly 20 years following the 2003 Northeast Blackout,” a major cause of which was trees growing into transmission rights of way. The regional entity noted that FAC-003 was one element of the ERO’s response to the 2003 blackout, and that compliance with the standard “is a fundamental expectation of industry.” ReliabilityFirst said the violation “posed a serious risk to the reliability of the” electric grid. 

To mitigate the issue, PPL removed the tree that caused the outage and restored the affected line. It then performed a gap analysis on its TVMP to find potential areas for improvement, updated its models so LiDAR data will better reflect the reality of the system, updated its TVMP, and completed an extent of condition plan to identify and address any additional issues. The utility certified its completion of mitigation activities to ReliabilityFirst on Jan. 22, 2024. 

NPCC Settles Nuclear Plant’s Issues

NPCC’s settlement was filed in NERC’s monthly spreadsheet notice of penalty Aug. 29. FERC’s Sept. 27 filing said it also would not review this agreement. 

In the settlement, the RE asserted the utility violated three requirements of PRC-023-4 (Transmission relay loadability), which were filed as three separate infringements in the spreadsheet NOP. The infringements involved the utility’s nuclear energy division and its facilities at the Nine Mile Point Nuclear Generating Station: Nine Mile Point Unit 1 (NMP1), Nine Mile Point Unit 2 (NMP2) and the James A. FitzPatrick Nuclear Power Plant (JAF).  

Constellation submitted a self-report for the three violations July 14, 2020, the settlement said. The report indicated that two protective relays at JAF “were misclassified by the previous owner.” According to Constellation, the relays were load responsive and therefore should have been categorized under PRC-023-4, Requirement R1. In a subsequent extent of condition review, the utility found a 115-kV line overcurrent relay at NMP1 also was noncompliant. 

Along with this infringement, Constellation said it was in violation of Requirement R3 for failing to agree with its planning coordinator on the use of two 115-kV lines at NMP2. Constellation owns 82% of NMP2, with the rest held by the Long Island Power Authority; however, Constellation is the sole operator of Units 1 and 2. 

Finally, Constellation told NPCC that it had “failed to provide its [PC], transmission operator and reliability coordinator with an updated list of circuits associated with the applicable JAF transmission line relays,” a violation of PRC-023-4 Requirement R4. The utility indicated it had found two separate instances of noncompliance: the first from January 2018 to November 2019, caused by a failure of the previous owner’s preventive controls, the second from January to April 2022, caused by a failure of the utility’s notification controls. 

To mitigate the issues, Constellation outlined its strategies for modifying preventive relay settings and completed an extent of condition review for the JAF and NMP1 units, enhanced its guidance for implementation of NERC standards on the NMP2 case and generated a recurring activity to track compliance with R4. 

NPCC noted that Constellation’s self-reporting and cooperation during the investigation process, lack of previous noncompliance with the standard and willingness to settle the matter as factors in penalty assessment. It also noted that no events or harm occurred during any of the noncompliances.