FERC has granted a solar developer’s request for a 28-month extension of its commercial operation deadline, finding that it acted in good faith to develop the facility (ER23-2603).
Twelvemile Solar Energy requested the extension in August for its planned 100-MW solar farm in Oklahoma that will interconnect with the SPP system. It executed a generator interconnection agreement with SPP and Oklahoma Gas and Electric in January 2019, reflecting a December 2020 commercial operation date. That date was extended in January to this December because of schedule disruptions caused by the COVID-19 pandemic and U.S. trade restrictions on imported solar equipment.
The developer said the pandemic and trade action created a “constrained” market in which demand for utility-scale PV panels considerably exceeds available supply.
The GIA included a provision that it could be terminated should Twelvemile Solar fail to meet the commercial operation date for three consecutive years.
FERC said in an Oct. 19 ruling that the request meets the commission’s criteria for granting waivers: The developer acted in good faith to develop the facility in accordance with the GIA; the waiver was limited in scope and applied only to the deadline; it addressed a concrete problem; and granting it would not result in undesirable consequences.
RENSSELAER, N.Y. — NYISO said it will submit a partial compliance filing for FERC Order 2023 early next month, aiming to get a head start on full compliance and minimize challenges associated with the transition to a new interconnection process.
NYISO attorney Sara Keegan told the Interconnection Issues Taskforce Oct. 20 that the ISO “wants to hit the ground running” in complying with FERC’s order, which seeks to clear backlogged interconnection queues through a clustered study approach. (See FERC Updates Interconnection Queue Process with Order 2023.)
NYISO’s partial filing will request that FERC eliminate the system reliability impact study (SRIS) requirement for pending queue projects, provide more options for pending projects to proceed through the queue and eliminate developers’ option for detailed feasibility studies.
Thinh Nguyen, NYISO senior manager of interconnection projects, said the proposals “seek to streamline the study process” and remove redundancies by “eliminating any unnecessary parts of the study process.”
Phasing out certain queue studies lets staff allocate their “limited resources more wisely,” since they are not only working to comply with Order 2023, but also still reviewing projects moving through the ISO’s current interconnection processes, Nguyen added. (See NYISO Begins 2023 Class Year with Nearly 100 Projects.) The ISO’s last interconnection SRIS project scopes will be presented to the Operating Committee for approval this month.
Zachary Stines, director of wholesale market development at Borrego Solar, asked why NYISO was making only a partial compliance filing.
Keegan responded that the partial filing is “very limited,” covering only what the ISO plans on doing during the interim period between December and the effective date of the full compliance filing.
“We want to be ready by the first cluster and be able to put all our resources into that, and not have to be winding down studies that provide no benefit in the new process,” she said.
Nguyen concurred, saying later, “We want to avoid shooting from the hip and be able to get everything figured out as quickly as possible for developers.”
Staff promised to continue the discussions and present stakeholder comments on the ISO’s proposals at future IITF meetings.
Compliance Extension Request
Staff also reiterated that NYISO intends to seek an extension of the Order 2023 compliance deadline from Dec. 5 to the end of January or start of February. (See NYISO to Ask FERC for Order 2023 Compliance Extension.)
On Oct. 2, the New England Power Pool Participants Committee requested a 45-day delay of the deadline. That followed an Aug. 28 filing by SPP, PJM and MISO requesting that FERC delay the compliance date from 90 days after the final rule’s publication in the Federal Register until at least 90 days after the commission issues a substantive order addressing arguments on clarification and rehearing (RM22-14).
The commission issued a notice Sept. 28 noting that rehearing requests in the docket were rejected after FERC failed to respond within 30 days. The three RTOs subsequently filed petitions asking federal appellate courts to review Order 2023. Other challenges have been filed by PacifiCorp, First Energy and Advanced Energy United.
Staff at the IITF noted that the ISO’s motion could be filed irrespective of the commission’s decision on the other RTOs’ extension request.
“We may file before the commission decides, since we expected an order by now on the [other extension requests], and we will probably ask for an [extension] tailored to our particular circumstances,” Keegan said.
Keegan said NYISO is looking for flexibility from the commission to minimize the impacts associated with transitioning to Order 2023’s cluster study processes.
“It might be longer or shorter than other [requests],” Keegan added, “but we have a unique situation in terms of the timing of our queue reforms.” He said the ISO wants to get everything into place before the start of the first cluster.
This need for flexibility was echoed in the compliance extension motions filed by other RTOs, who argued it would be difficult for them to both comply with FERC’s directives and ask for more details on Order 2023.
“Requiring transmission providers to make compliance filings while many have pending requests for rehearing and clarification creates regulatory uncertainty and imposes a regulatory burden on some transmission providers and stakeholders as they seek to comply with the final rule while also undertaking their own RTO-specific reform effort,” read the motion filed jointly by PJM, MISO and SPP.
A coalition of commercial fishing interests, hotel and motel owners, and an ocean-focused environmental group have filed suit against the Bureau of Ocean Energy Management to overturn approval for New Jersey’s first offshore wind project, Ocean Wind 1.
The suit, filed Oct. 17 in U.S. District Court in New Jersey, argues that BOEM “failed to comply with numerous statutes and their implementing regulations” when it approved Danish developer Ørsted’s 1,100 MW project on July 3. The suit asks the court to “invalidate” the approvals.
“Plaintiffs’ interests, all of which are dependent upon the natural state of the ocean, will be irreparably harmed if the challenged actions are not reversed as the law requires,” the suit states.
Also named as defendants are: BOEM director Liz Klein; the Department of Interior and its secretary, Deb Haaland; and the National Marine Fisheries Service (NMFS) and its assistant administrator, Janet Coit.
The suit is the latest of several suits filed seeking to stop the project, including one filed by three opposition groups — Save Long Beach Island, Defend Brigantine Beach and Protect Our Coast NJ — whose appeal filed in June in Superior Court challenged state permit approvals for Ocean Wind. Cape May and Ocean City, a shore community, each have filed a legal appeal seeking to overturn the approval by the New Jersey Board of Public Utilities (BPU) of an easement needed for the project. (See Lawsuits Mount over NJ OSW Projects as Opposition Digs in.)
Aside from Cape May County, the plaintiffs in the suit include: the Garden State Seafood Association, which represents commercial fishermen, shore-based seafood processors, commercial dock facilities, seafood markets and restaurants; LaMonica Fine Foods, a fish processing company; Surfside Seafood Products Food, a clam fishing and processing company; and Lund’s Fisheries, a seafood company that manages 19 ships and handles 450 metric tons of food a day.
Other plaintiffs are Greater Wildwood Hotel and Motel Association, which represents 236 hotels and motels on the five-mile Wildwoods barrier island, and Clean Ocean Action, an environmental group that focuses on marine issues and has been vocal in its opposition to the state’s OSW projects.
Lack of Progress
Cape May posted a release on its website stating that federal regulators “have abandoned their obligations to protect the environment and Atlantic-coastal marine life in favor of an inappropriate collusion with Big Wind interests.”
“We spent the better part of two years trying to negotiate with Ørsted to redesign this project in a way that would cause less damage to the environment and less damage to our tourism and fisheries interests,” Cape May County Board of Commissioners Director Len Desiderio said in the release. “Our reasonable proposals fell on deaf ears as state and federal regulators rubber-stamped permits to rush the Ocean Wind One project to approval.”
In the latest suit, Cape May County, which has in the past been represented by Michael Donohue, a former Superior Court judge, also is represented by Roger J. Marzulla and Nancie G. Marzulla, Washington, D.C., attorneys who represented a coalition of fishing interests in a case seeking to overturn federal permits issued to Vineyard Wind 1.
BOEM did not respond to a request for comment late Wednesday.
A spokeswoman for Ørsted, which is not a named defendant, said it would not comment on pending litigation.
The lawsuit follows a federal court ruling in Massachusetts on Oct. 12 that rejected two federal lawsuits challenging environmental permits and construction approvals for the Vineyard Wind project, the first commercial-scale OSW farm in the U.S. The plaintiffs included fishing groups and Responsible Offshore Development Alliance, a coalition of fishing industry associations and fishing companies.
New Jersey has approved three OSW projects in two solicitations — the 1,100-MW Ocean Wind 1, the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores — and is midway through a third solicitation. The BPU is expected to announce which of the four bidders have secured approval early next year.
Endangered Species
The lawsuit comes amid a steady increase in opposition to the state’s OSW projects, which the commercial fishing sector has opposed for several years due to concerns about the impact on their industry.
The lawsuit states seven causes of action in which federal authorities erred in their support for the Ocean Wind 1 project, including the claim that BOEM and NMFS violated the National Environmental Policy Act by “failing to take a hard look at the environmental impacts of the Ocean Wind 1 Project” when BOEM issued its environmental impact statement. The suit says the agencies “unlawfully” limited alternatives to the project, such as smaller projects with fewer turbines.
The defendants also violated the endangered species act by failing to “adequately consider the dangers to these protected species,” including their “failure to require enough mitigation measures to prevent the injury and death of the North Atlantic right whale and other protected species.”
The agencies also violated the Coastal Zone Management Act by approving a project that is not consistent with New Jersey’s own coastal management rules, the suit argues. These include rules designed to protect the “reproductive, spawning and migratory patterns or species abundance or diversity of marine fish,” the suit says.
ISO-NE can consider transmission-only battery storage as an option to address transmission system issues, FERC ruled Oct. 19. The commission-approved filing allows the operators of these assets to recover costs through transmission rates, while imposing tight restrictions around how the storage must be operated.
The tariff changes “will result in the selection of SATOAs [Storage as Transmission-Only Assets] only when those resources perform a transmission function, consistent with commission precedent,” FERC wrote, noting that it had approved SATOA filings for MISO in 2020 and SPP in 2023.
SATOAs will be largely prohibited from participating in ISO-NE’s markets in order to “minimize market impacts and ensure a SATOA does not receive dual recovery of its costs via both cost-of-service rates and market-based rates,” ISO-NE wrote in its filing.
To be selected as a SATOA, battery facilities must be identified as the best solution in a transmission study, connect directly to pool transmission facilities and be controlled by ISO-NE. The RTO will also limit the total capacity of SATOAs to 300 MW across the system and 30 MW per substation.
“In these circumstances, SATOAs are properly characterized as transmission assets, and the costs of a SATOA are appropriately recoverable through transmission rates,” FERC wrote.
ISO-NE’s filing was supported by a range of stakeholder groups, with some calling on the RTO to go further in enabling batteries as storage solutions. Advanced Energy United (AEU) and the Union of Concerned Scientists (UCS) both called the filing a “first step.”
“This is only a first step in expanding the capability of the transmission system through the deployment and recognition of energy storage,” wrote Michael Jacobs of UCS, adding that the organization “urges the commission to take action to further expand opportunities for storage as transmission.”
Jacobs added that storage should be included as an option to meet transmission needs identified in the interconnection process for large generators and said ISO-NE’s set of constraints “omits opportunities for economic or reliability improvements.”
Caitlin Marquis of AEU wrote that the SATOA capacity limits are “reasonable as ISO-NE gains experience and comfort with the use of storage as a transmission asset but should be evaluated over time to ensure they do not serve as an artificial and unnecessary barrier to SATOA participation.”
Marquis said SATOAs should eventually be allowed to participate in ISO-NE’s markets to tap into their full value.
“With the right guardrails in place, allowing storage to participate as both a transmission and market asset would optimize utilization of storage resources and maximize benefits to ratepayers,” Marquis wrote.
But the New England Power Generators Association (NEPGA) called the limits “critical” to ensuring that SATOAs do not result in price suppression and operational issues.
“Price suppression is a real concern,” NEPGA wrote. “When locational energy and ancillary service prices do not reflect the marginal economic cost of production, but instead are suppressed, for example, by cost-of-service resources indifferent to the economics of the market as ‘price-takers,’ the markets are less attractive to capital and thus less able to satisfy the common goal of cost-effective and efficient electric system reliability.”
In approving ISO-NE’s filing, FERC denied NEPGA’s request that the RTO’s Internal and External Market Monitors report on how effectively the SATOA limits mitigate adverse market effects. The commission said AEU’s and UCS’ calls for expanded uses for SATOAs were outside the scope of the proceeding.
FERC ordered ISO-NE, NEPOOL and New England Transmission Owners to submit the effective date of the SATOA changes, which ISO-NE did not specify in its filing.
Republicans on the Senate Committee on Energy and Natural Resources attempted to paint the Department of Energy’s Loan Programs Office (LPO) and other programs as tarnished with political and financial conflicts of interest during a Thursday hearing intended to examine the agency’s decision-making process for competitive loans and grants.
Sen. John Barrasso (R-Wyo.), the committee’s ranking member, opened the session with a blistering attack on the Inflation Reduction Act (IRA) and LPO Director Jigar Shah, who was one of three DOE officials at the hearing.
He was joined by David Crane, under secretary of infrastructure, and Teri L. Donaldson, the department’s inspector general.
DOE Under Secretary David Crane | Senate ENR
Citing a report he released Thursday, Barrasso labelled the IRA “irresponsible, reckless and alarming,” arguing that it was weakening the U.S. and increasing the country’s dependence on China for critical minerals and other clean energy technologies.
“It can’t be salvaged; it needs to be repealed,” he said.
His attack on Shah centered on the LPO director’s founding of an industry group, the Cleantech Leaders Roundtable (CLR), in 2017. Barrasso said the CLR “appears to be a gatekeeper for companies seeking DOE funding” and touts its relationship with Shah, who has spoken at several group events, including dinners.
Noting that the LPO recently announced a $3 billion loan to a solar company, Sunova, that is a member of the roundtable, Barrasso told Shah, “I think it’s a very bad look for you personally and a very bad look for the Department of Energy.” He then pressed Shah to commit to severing any ties with the group as long as he is at DOE.
Committee chair Sen. Joe Manchin (D-W.Va.) defended the IRA and Shah. While he continues to criticize the Biden administration’s implementation of the law, Manchin called it “an all-in policy that’s working.”
“We’re producing more energy in the country today than ever in the history of the United States of America,” he said, citing high figures for oil, natural gas and solar and wind production. He also noted that he and certainly other lawmakers regularly attend industry conferences, like CERAWeek, where attendees pay to hear him speak.
Sen. Joe Manchin (D-W.Va.) | Senate ENR
While agreeing to keep his distance from CLR dinners, Shah also countered Barrasso’s questions by noting that career federal staffers oversee the evaluation and vetting of LPO applications, and he personally has no part in the decision-making on individual loans.
“I’m more accessible than a ham sandwich,” Shah said of his attendance at myriad industry conferences. “I go to lots of places, wherever American innovators and entrepreneurs need to meet me, so that they can be convinced that this country wants them to onshore and reshore their technology here in this country.”
Sen. Martin Heinrich (D-N.M.) also responded to Republican barbs about Shah’s attendance at industry conferences. “After years and years of people complaining that government is unresponsive to private industry, we finally have an administration who will meet anyone with any technology, whether it’s fossil or renewable or nuclear, and actually work with them in a way that is friendly to the private sector,” he said.
“And that is not something I think we should be discouraging. We should expect more.”
‘They Take Their Time’
Crane came in for his share of heavy interrogation from Sen. Bill Cassidy (R-La.), who wanted to know why his state was not chosen as one of the seven regional hydrogen hubs announced on Oct. 13. The hubs are being funded with $7 billion from the Infrastructure Investment and Jobs Act. (See DOE Designates Seven Regional Hydrogen Hubs.)
Sen. Bill Cassidy (R-La.) | Senate ENR
“I’m told that the merit reviewers of the Louisiana application, several of them did not provide any comments or ask any questions regarding the application,” Cassidy said. “In fact, there’s no evidence that they actually reviewed it. What I’m worried about is that the fix was in before we even started.”
He also suggested that the hubs designated for awards are predominantly in states with Democratic lawmakers in Congress.
Like Shah, Crane stressed that no politics were involved in the review of the applications. “The independent merit review, the federal panels, the selection officers are all career civil servants, and they evaluated many, many criteria,” he said.
Crane also explained that, as laid out in the IIJA, the regional hubs were required to be in different parts of the U.S., and “the Gulf Coast had multiple very, very strong [applications].” Texas, which like Louisiana has two Republican senators, was designated for development of a Gulf Coast hub.
Crane said funding applications for the hubs and other DOE programs all go through the agency’s recently established vetting center, which “takes as much time as they need to review all that they need to review.”
Referring to the hub announcements and the $3.46 billion for 58 grid resilience and improvement projects announced Wednesday, Crane said, “If it had not been for the vetting … process, we would have been announcing those awards at the beginning of September. So, they take their time. It’s only when they’re done and they’re comfortable that we move forward with selection.” (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
Inspector General Underfunded
Political theater aside, the main focus of the hearing, raised by both Manchin and Barrasso, centered on ensuring that neither IIJA nor IRA dollars are going to projects that might have connections to China or other U.S. adversaries, such as Russia or Iran.
Barrasso and other GOP lawmakers had criticized the agency for a proposed $200 million grant to Microvast, a U.S. battery manufacturer with a Chinese subsidiary. Earlier this year, DOE announced it had ended negotiations with the company, which would not be receiving the grant.
Sen. John Barrasso (R-Wyo.) | Senate ENR
More recently, Barrasso and others have zeroed in on the LPO’s announcement of an $850 million conditional loan guarantee to Kore Power, an Idaho-based battery manufacturer that is building a gigafactory in Arizona. The catch is the company previously has done its manufacturing in China and will be licensing technology from a Chinese company.
Donaldson, DOE’s inspector general, said the department’s due diligence and vetting processes still are not rigorous enough and could put taxpayers’ dollars at risk because of the huge amounts of money flowing through the department and the speed at which awards, loans and grants are being made.
More than 70 new programs are “all trying to develop criteria, including due diligence criteria,” Donaldson said. “You have massive amounts of money moving quickly. All these things happening at once create a level of risk that may candidly be unprecedented in terms of the amount of federal money moving in such a complicated landscape.
Teri L. Donaldson, DOE inspector general | Senate ENR
“I cannot say often enough that this is a very risky landscape,” Donaldson said. “On the issue of not funding our adversaries, I am greatly concerned about how things are going in that regard.” The vetting center is a step in the right direction, she said, but it is understaffed and has no written procedures.
Similarly, Donaldson’s own office is critically underfunded, she said, and her requests for more funding so far have been unsuccessful. According to her written testimony, only $62 million of the $64 billion DOE received from the IIJA were earmarked for her office.
At EPA, the inspector general’s office received $269 million of the $61 billion EPA received from the law.
Shah defended the LPO’s vetting process, saying the office “has an ability to do due diligence on these projects that many private sector banks don’t have because we have access to the 10,000 engineers, scientists and experts” at DOE and its national laboratories.
Further, many of the tech startups seeking federal loans are in the process of commercializing technology originally developed with DOE funding, he said. “For many of these technologies, which are frankly scary to the private sector — it is why the LPO was created — we can do rigorous due diligence and look back into demonstration projects and other data that we have to see whether the technology will work.
“We never take ‘will it work, or won’t it work’ risk today here at the LPO,” Shah said. “We do take execution risk, scale-up risk, a lot of other risks that are real risks that we have to do due diligence on.”
On the issue of Chinese influence, Shah outlined a list of steps the LPO has taken to avoid such investments, such as ensuring foreign entities cannot get board representation at companies receiving federal loans.
“Second, we make sure that all [intellectual property] licenses are one way, so that the technology comes to the United States tied to the American worker, but no additional innovations that occur here can go back to that country,” he said.
FERC issued a final rule Thursday directing NERC to develop standards to improve the reliability of inverter-based resources (RM22-12).
The final rule, which had not been posted as of Thursday evening, covers solar photovoltaics, wind, fuel cell and battery storage, which make up most of the projects in the interconnection queues.
“These standards will help us solve one of the biggest problems we’re facing as we make the transition to clean energy resources,” FERC Chairman Willie Phillips said at the monthly open meeting. “We need to make sure that these promising new technologies can enhance, not weaken, reliability of the grid. We mean it when we say that at FERC, reliability is, and remains, Job No. 1.”
NERC was directed to develop rules addressing IBR data sharing, model validation, planning and operational studies, and performance standards. The reliability organization has to submit the rules in three tranches, with each one due no later than Nov. 4 over each of the next three years.
The order gives NERC 90 days to make a filing that includes a detailed, comprehensive standards development and implementation plan.
IBRs use electronic devices that change the direct current power produced by generators into alternating current power that is then transmitted on the bulk electric system. The concern is that IBRs can respond to grid disturbances differently from traditional resources; at least 12 events have occurred on the bulk power system in which 1,000 MW of IBRs tripped offline, showing the risks they can pose absent reforms, Phillips said.
“We have a lot of clean energy and renewable energy resources that are being connected to the grid. And this new rule is a great step to address what we see as reliability concerns regarding this transition” Phillips said during the open meeting.
“When appropriately programed, IBRs can provide operational flexibility. And the ability of IBRs to perform with precision, speed and control could mitigate disturbances on the bulk power system,” he added.
Commissioner James Danly called the rulemaking “long overdue” and the “most important action we’ve taken on reliability in the last year or two.”
Commissioner Allison Clements said IBRs offer “an exciting opportunity for dynamic response and for increased operational flexibility.”
She said she was disappointed that the final rule only directs NERC to consider requiring transmission owners to share data with IBR resources. She said NERC should require such sharing be required.
“The record in the preceding indicates the generator owners require data to support the modeling and performance requirements we are now directing NERC to create,” she said. “I think it’s kind of tough to make people bake the cake without giving them the recipe.”
Clements said most current IBRs in place today should be able to meet the updated standards with simple software updates, but some older models may not be able to do so.
The rule directs NERC to consider exceptions for these older IBRs. “I hope to see such exceptions, as doing so will allow these older resources to continue to provide value to customers without compromising system reliability,” she said.
QUEBEC CITY — Ingrid Rayo’s fellow panelists nodded when she said participants in next month’s GridEx security exercise should focus on the people and organizations most relevant to their mission — in contrast to previous years’ emphasis on encouraging participation from as wide a range of groups as possible.
“I remember in one GridEx that we had a … daycare center right next to the control center that we were hosting GridEx from,” said Rayo, a senior consultant on governance, risk, cybersecurity and compliance at Burns & McDonnell, at this week’s GridSecCon security conference in Quebec City. “We pulled them in, and there was also a news station behind us and we pulled it in. And so we had all these people interacting, and the next thing you know, the news station was talking about the [daycare]. We forgot about the grid, because we were focused on the kids.”
Amid chuckles from the other panelists, Rayo explained that while there is value in getting buy-in from stakeholders in other sectors on which the electric industry depends — such as the telecommunication and natural gas sectors, which participated in GridEx VI in 2021 — it is easy to “take a rabbit hole” and overcomplicate the scenario. (See GridEx VI Incorporates Recent Cyber Lessons.) She recommended utilities “focus on those individuals that are truly active in the recovery plan and incident management” to make best use of their efforts.
The Electricity Information Sharing and Analysis Center (E-ISAC) holds GridEx every two years to help electric utilities and other stakeholders test and improve their security incident response plans. The exercise consists of a two-day distributed play exercise, with the E-ISAC creating a general scenario that each participating organization customizes for its own workforce, along with an executive tabletop for executives from the electric and related industries, along with U.S. and Canadian government officials.
Moderating the panel was Jesse Sythe, the E-ISAC’s GridEx Program Manager, who noted that GridEx distributed play scenarios have “consistently been ahead of reality,” with elements such as physical attacks on transformers in 2013’s GridEx II echoing that year’s shootings at California’s Metcalf substation. (See Substation Saboteurs ‘No Amateurs’.) He observed that GridEx IV in 2017, “in our most prescient move,” incorporated the impacts of a pandemic on workforce participation.
The distributed play for GridEx VII is scheduled for Nov. 14-15; Erin Rowe, the director for incident response at MISO who is organizing the distributed play exercise for her organization, said that this year she wants her team to “practice like we respond.” To that end, Rowe said, she intentionally sent out invitations with no location specified for the event.
“I don’t want them to sit in the conference room waiting, I want them to actually get that phone call, get the [Microsoft] Teams message, whatever mode that communication is going to come by, I want them to actually have to do it and go through the process for how we escalate that incident,” Rowe said.
Panelists emphasized that personal interaction is key to encouraging participation in GridEx. Saad Ansari, a senior specialist for emergency preparedness at Ontario’s Independent Electricity System Operator, assured audience members they don’t “have to reinvent the wheel” by scheduling face-to-face meetings just to discuss the exercise, but they should try to “leverage existing channels” by, for example, adding a GridEx discussion item to already-scheduled meetings.
Ashley Wemhoff, the incident response drill coordinator for the Nebraska Public Power District, acknowledged that organizations new to GridEx may feel intimidated by the idea of the two-day exercise and observed that participation in both days is not required. Several utilities in Nebraska are taking part only on the first day, she said.
Asked by Sythe for further advice on encouraging participation in GridEx, panelists urged organizations to try to emphasize the fun aspects of the event, which they acknowledged could be draining. Wemhoff jokingly suggested including glitter bombs in invitation packages, while Rayo said appealing to employees’ greed can be a winning strategy.
“People love swag, right?” Rayo said as the crowd laughed. “If you give them a free shirt, a free hat, whatever … as long as we have some [free gifts], you will get people to come to you and they will want to participate. It’s actually marketing for your next GridEx, because now they want to have the T-shirt like everybody else. We’re all a community, we all want to look alike and feel like we’re part of something.”
FERC on Thursday approved a transmission asset swap between Idaho Power and PacificCorp as part of the companies’ plans to develop a 300-mile-long, 500-kV line that will deliver Wyoming wind to the Pacific Northwest and hydropower to the Intermountain West (EC23-111).
In August, Idaho Power said it expected to begin construction work on the Boardman to Hemingway Transmission Project (B2H) this fall. The line between northeastern Oregon and southwestern Idaho is expected in service by June 2026.
The two companies said they sought the transfer to improve the alignment of their transmission assets with their load service areas after the Bonneville Power Administration dropped out as a partner in the B2H project.
Although Bonneville initially had proposed to participate in the project to facilitate service to wholesale customers in southeastern Idaho, it withdrew, choosing to take long-term firm transmission service from Idaho Power.
The transaction will give PacifiCorp 300 MW of west-to-east transmission capacity and 600 MW of east-to-west transmission capacity over the transferred facilities. Idaho Power will gain 200 MW of bi-directional transmission capacity over facilities through Idaho and more than 600 MW of capacity in the Goshen, Idaho, area to support network service from Idaho Power to BPA’s southeastern Idaho wholesale customers.
The commission concluded the transaction would not harm horizontal competition because it does not involve any generation assets and vertical competition would be unaffected because the transmission facilities involved will provide service under FERC-approved Open Access Transmission Tariffs. It also said the deal would not impact wholesale rates because the assets will be transferred at net book value with no acquisition premiums.
The commission conditioned its approval of the deal on the parties’ completion of a memorandum of understanding to address Utah Associated Municipal Power Systems’ (UAMPS) concern that the transaction could impact transmission service to UAMPS’ members in southeastern Idaho.
“We find that applicants have sufficiently addressed UAMPS’ concerns, provided that they follow through on their commitment to enter into the memorandum of understanding,” FERC said, ruling UAMPS’ request to be held harmless “moot.”
In a separate order, the commission also approved revisions to add the B2H project to Idaho Power and PacifiCorp’s joint ownership and operating agreement over transmission facilities in Idaho, Oregon, Washington and Wyoming (ER23-2463).
The B2H project will run between a new switching station near Boardman, Ore., and the existing Hemingway substation near Melba, Idaho. Idaho Power says the project, which it identified in its 2006 integrated resource plan, is the least-cost alternative for serving its customers in fast-growing southern Idaho and eastern Oregon. PacifiCorp said the line will aid its service into northeastern Oregon and provide a second connection between the PacifiCorp-East and PacifiCorp-West balancing authority areas, currently connected only by the Midpoint-to-Summer Lake 500-kV line.
Idaho Power said the project will connect two regions whose peak production of clean power is mismatched with their peak demand. The Pacific Northwest sees energy demand peak in the winter, driven by heating loads, while its peak hydropower production is in the spring and summer. In contrast, electricity demand in the Intermountain West peaks in the summer from irrigation and air conditioning loads, while its wind energy peaks in the winter.
FERC is moving to grant a solar developer’s request to force the Arizona Electric Power Cooperative to allow interconnection.
The proposed order FERC issued Thursday gives AEPCO and developer THSI 30 days to negotiate the terms. If FERC finds the terms acceptable, it will issue a final order reflecting them. If the two sides are unable to reach agreement, FERC will prescribe the terms, consider the two sides’ positions, then issue a final order.
Docket TX23-5-000 centers on the Three Sisters Solar Project, a 300-MW solar array with 300 MW/1,200 MWh of battery storage proposed in southeast Arizona by BrightNight and its subsidiary, THSI.
THSI formally submitted the interconnection request to AEPCO in November 2019. After multiple studies, the dispute arose. In May 2023, AEPCO notified THSI it had removed Three Sisters from the interconnection queue.
In June 2023, THSI asked FERC to direct AEPCO to provide interconnection, finalize the large generator interconnection agreement and restore Three Sisters to its position in the queue.
From early July to early September, AEPCO protested; three industry associations (American Public Power Association, Large Public Power Council and National Rural Electric Cooperative Association) sought to intervene, then also jointly protested; and THSI, AEPCO and the power authorities then filed successive arguments, protests and responses to each other’s filings.
FERC’s proposed order includes the following points and counterpoints by the two sides:
THSI said it originally proposed an Aug. 2, 2022, commercial operation date, then early this year proposed Dec. 15, 2025. It said AEPCO initially raised no concerns but on May 16, 2023, said the new date was a material modification that would necessitate a new interconnection study, and that Three Sisters had been removed from the queue.
Informal dispute resolution attempts were unsuccessful, THSI said.
THSI said all necessary interconnection studies had been performed and found no potential reliability issues and no significant need for network system upgrades. Further, the parties had already negotiated a large generator interconnection agreement.
So, there is little else to discuss, THSI said.
But AEPCO countered there are genuine issues of material fact because there is no certainty whether or how much Three Sisters would serve the wholesale market.
AEPCO said THSI’s initial interconnection request made no mention of something that later came up in a state environmental review: a co-located green hydrogen production facility that would be an off-taker for the solar power generated there. This makes Three Sisters’ grid output uncertain, it said.
But THSI has not secured the right to serve a retail load such as the hydrogen plant, AEPCO said, adding that an AEPCO member has state approval to provide power to the plant.
(THSI counters that there is no binding agreement with the hydrogen facility potentially to be built on site.)
AEPCO says there is no controversy over its willingness to interconnect with THSI, only over whether it must maintain THSI’s position in the queue.
AEPCO questioned whether the public interest is served by allowing a developer to hold an interconnection queue position for more than five years, potentially to the detriment of other developers, for a project that might provide only behind-the-meter power to an industrial end-use off-taker.
AEPCO also laid out multiple reasons it believes FERC lacks jurisdiction to consider the matter. (The power associations made similar arguments. THSI offered counterarguments.)
AEPCO asked FERC to dismiss THSI’s request with prejudice, preserve its right to update the studies and allow it to participate in evidentiary hearings if the matter is not dismissed.
In its proposed order, FERC explains why it does have authority to consider THSI’s request, then explains why it is granting the request.
FERC said it finds the public interest would be served by directing AEPCO to provide interconnection service to THSI because precedent holds that transmission availability enhances competition in power markets, which should result in lower prices for consumers.
A potential future hydrogen facility does not necessitate new interconnection studies, FERC said, because THSI has made no changes to its 300-MW interconnection request.
Nor is there any genuine issue of material fact that would call for an evidentiary hearing, FERC wrote.
Market monitors from all of FERC’s six jurisdictional grid operators have endorsed calls for a NERC-like gas reliability organization.
The monitors sent the commission a letter Oct. 10 endorsing the recommendations from the North American Energy Standards Board’s (NAESB) Gas Electric Harmonization Forum, issued in July. (See NAESB Forum Chairs Push for Gas Reliability Organization.)
“In a time of unprecedented transformation, the reliability of the bulk electric system (BES) is increasingly dependent on the reliability of natural gas-fired generators,” the monitors wrote. “As noted in multiple forums, recent winter storm and summer heat events have highlighted that the electric and natural gas systems do not function in an integrated manner when needed most, resulting in the loss of hundreds of lives and over $100 billion in economic damage from the 2021 and 2022 winter storms alone.”
The letter was signed by PJM Independent Market Monitor Joe Bowring, SPP Market Monitoring Unit Vice President Keith Collins, CAISO Department of Market Monitoring Executive Director Eric Hildebrandt, ISO-NE Market Monitoring Executive Director David Naughton and Potomac Economics President David Patton, the market monitor for MISO and NYISO.
“We recognize that the report’s primary recommendation is that an optimal solution likely requires federal legislation that creates a NERC-like organization for the natural gas industry,” they said. “However, that outcome is uncertain. Given that uncertainty, we strongly support FERC’s past, current and future efforts to improve the reliability of natural gas-fired generators within the North American BES.”
FERC Chairman Willie Phillips highlighted the letter and its endorsement of the recommendations at the commission’s regular meeting Thursday.
“The primary recommendation of the NAESB report is the establishment of a NERC-like organization for the natural gas industry,” Phillips said. “And I welcome the support of all six independent market monitors, not only for NAESB’s recommendations, but their encouragement that FERC, quote, ‘take actions to use recommendations in this report.’ I could not agree more.”
The market monitors think gas-electric harmonization is a key issue that needs to be addressed, Bowring said in an interview.
“It’s essential to maintaining the reliability of electric power markets as we … transition to more renewables,” Bowring said. “We believe that gas is going to continue to be necessary. And it’s essential that to the extent possible, we get better information, more transparency and more coordination between the two industries.”
While the recommendations are national, Bowring said that they leave enough room for the different regional markets to adapt them to their specific needs.
“There needs to be somewhat different solutions, depending on the market, for sure,” Bowring said.
For instance, PJM currently has a lower level of renewables than most of the ISO/RTOs, but it is facing a very high level of expected coal retirements and that means even more gas will be needed, he said.
Bowring said the most important recommendations from NAESB center on transparency. In PJM, it would benefit to know when pipelines invoke their tariffs to require generators to take the same amount of gas at all hours — which impacts power plant’s ability to ramp up and down — and when they require strict adherence to their nomination schedules, because the gas trading day and power days do not align.
“One of the things that happened during Elliot was that PJM was not aware of these long nomination periods, and therefore they called on resources that couldn’t get gas because they hadn’t nominated it,” Bowring said.
Electric-natural gas harmonization has been a concern for years. Winter Storm Elliot last December was just one of five winter reliability events over the past decade that would have benefited from improved coordination. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.)
Although the years of talk have not produced enough changes, Bowring said he was hopeful the momentum around the issue would lead to substantive reforms this time. Dealing with the issue will involve both industries coming together to develop rules that are consistent with their relative incentives.
“The business models are somewhat inconsistent. But there have to be ways to coordinate,” Bowring said. “The idea is not to force anything on the pipelines, or force anything on the generators. But I think it’s in both sides’ interest to coordinate. For whatever reason, it hasn’t happened, and I’m hoping this is a wake-up call to both sides.”
