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November 1, 2024

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BOEM Designates Draft Wind Energy Area in Gulf of Maine

Federal regulators have designated a draft wind energy area in the Gulf of Maine, shrinking it substantially from its earlier stages and excluding a key lobster fishing area.

The 3.52-million-acre zone has a potential capacity estimated at more than 40 GW. It stretches as much as 120 miles off the New England coastline, and ranges across water too deep for wind turbines with fixed-bottom foundations.

The buildout instead will require floating turbines, which still are being developed and improved. They have begun to be installed only recently, three decades after the first fixed-bottom offshore wind farm was built off the coast of Denmark.

In announcing the draft wind energy area on Oct. 19, the U.S. Bureau of Ocean Energy Management touched on the newness of the floating wind sector, saying the Gulf of Maine presented an opportunity for the United States to take a leadership role.

The state of Maine hopes to do exactly that, and for years has been priming itself to reap the expected environmental benefits of floating wind and the economic benefits of leading its buildout.

The state has set a goal of 3 GW of offshore wind by 2040. The state university has been steadily researching designs; it floated a scaled-down turbine close to shore a decade ago.

BOEM is processing the state’s request for a research lease that would allow it to place up to 12 floating turbines rated at up to 144 MW in a 9,700-acre area of the gulf.

The trade group Business Network for Offshore Wind welcomed BOEM’s announcement. In a prepared statement, Vice President John Begala said: “Advancing leasing in the Gulf of Maine sustains that confidence and unlocks new investment in the U.S. floating offshore wind supply chain, giving our nation the opportunity to catch up with the global market in this emerging field. Floating offshore wind is also crucial to New England states, whose demand for new, clean power generation is predicted to grow from current levels as they move to decarbonize their economies.”

President Biden has set a national target of 30 GW of offshore wind by 2030 but lowered the goalpost for floating wind: only 15 GW, and not until 2035.

The extra time will allow for further research and development to address the technical challenges of floating wind.

The world’s deepest fixed-bottom wind farm stands in not quite 200 feet of water off the Scottish coast. In the Gulf of Maine, the area with the greatest wind energy potential is 600 to 800 feet deep.

The longer time frame also should allow the U.S. offshore wind industry time to overcome the financial and logistical problems it is struggling with.

Many of the fixed-bottom projects contracted but not yet under construction off the Northeast coast have run into major headwinds. Three are in limbo after reaching deals to cancel their power purchase agreements, and developers of others are threatening to pause or cancel their projects unless they get more money.

However, policymakers, the offshore wind industry and its advocates continue to mark achievements amid the struggles. They expect the need for clean power to smooth out the growing pains offshore wind is experiencing.

The Business Network for Offshore Wind presented both sides of the ledger in its third-quarter report, issued Oct. 17.

BOEM Director Elizabeth Klein said in a news release that public comment and stakeholder concerns were incorporated into the draft wind energy area. The boundaries do not include Lobster Management Area 1 or North Atlantic Right Whale restricted areas, for example, and there is a six-mile buffer around important groundfish areas. BOEM also said it tried to avoid a majority of historic and present fishing grounds of Tribal Nations.

Gov. Janet Mills (D) and the state’s congressional delegation earlier this year urged these considerations. In a prepared statement Oct. 20, Mills said: “We look forward to reviewing the proposal in detail, but we are encouraged that the Bureau has initially listened to our concerns and those of the fishing community by excluding Lobster Management Area 1 in its draft.”

At an earlier stage of the process, BOEM’s draft call area had spanned 9.9 million acres and included Lobster Management Area 1.

Advocates for the fishing industry, the environment and labor hailed the removal.

“This is how the process is supposed to work,” Virginia Olsen, Executive Liaison of Maine Lobstering Union Local 207 said in a news release. “The federal government listened to the concerns of our fishing communities, and now they are sending a strong signal that an offshore wind industry that fundamentally harms the hardworking Mainers making their living on the water is neither in line with Maine’s values nor welcome in the Gulf of Maine.”

Publication of the Gulf of Maine Draft Wind Energy Area launched a 30-day public comment period.

Additional adjustments are expected to be made based on input received, BOEM said.

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FERC Allows Blackstone Subsidiary to Purchase 20% Stake in NIPSCO

A Blackstone subsidiary is free to acquire an almost 20% stake in Northen Indiana Public Service Co. after FERC’s consent Oct. 19.

FERC said Blackstone Investment Partner’s Blue Buyer, owned by funds managed by Blackstone, can scoop up 19.9% of NIPSCO for $2.15 billion without setting off adverse market impacts (EC23-99). But the decision caused Commissioner Mark Christie to cast doubts again on FERC’s review process and over the recent trend of big asset managers investing in the energy industry.

NIPSCO parent NiSource announced in late 2022 that it was looking for a buyer for a minority interest in the utility. CEO Llyod Yates said the sale will help pick up the tab on a 2040 net-zero emissions goal and approximately $15 billion in grid and gas infrastructure modernization and clean energy investments over the next five years. (See NiSource Selling Minority Interest in NIPSCO.)

The transaction includes a five-year hold harmless period for NIPSCO transmission customers to shield them from transaction-related costs.

Public Citizen and Citizens Action Coalition lodged a joint protest against the sale, arguing Blackstone will control two seats on the NIPSCO board of directors in addition to Blackstone already selecting a director of its choosing on FirstEnergy’s board. They also pointed out Blackstone controls one seat on the board of Texas-based natural gas company Cheniere Energy and another two seats on the board of subsidiary Cheniere Energy Partners. They said Blackstone members are becoming too commonplace on the boards of FERC-jurisdictional utilities.

FERC said Blackstone’s affiliations with energy companies won’t harm competition. It pointed out that FirstEnergy operates in PJM, while the NIPSCO transaction involves the MISO footprint.

“Regarding concerns over Blackstone’s ability to control boards of directors, we find that the proposed transaction will not adversely affect competition because our analysis … would not change even if Blackstone executives were to simultaneously serve on the boards of NiSource and FirstEnergy. This is because FirstEnergy’s utility holdings are located in PJM, while the relevant geographic market for the proposed transaction is MISO,” FERC said.

The commission said the sale won’t raise market power concerns because although Blackstone owns transmission facilities in other markets and an intrastate natural gas pipeline, the transmission facilities will be placed under RTO control when they become operational and the pipeline is located in Texas, far from the NIPSCO service area, although partially in MISO territory.

However, FERC said it couldn’t evaluate whether the acquisition would violate antitrust laws because its jurisdiction does not extend to the enforcement of the Clayton Antitrust Act.

Beyond that, FERC declined to take up Public Citizen and Citizens Action Coalition’s arguments that the transaction stands to raise rates not only for Indiana customers but MISO as a whole because Blackstone will exploit the state’s new right of first refusal (ROFR) law, which grants incumbent transmission owners first dibs to build lines approved by MISO. FERC said that contention was beyond the scope of its proceeding.

“Though joint protestors take issue with Indiana’s ROFR law, they have not identified any way in which the Proposed Transaction will adversely affect vertical competition,” FERC wrote.

NiSource said it will continue to control NIPSCO despite the transaction. It said that at the time it applied for the sale, affiliates of the Vanguard Group, T. Rowe Price Group and BlackRock each held more than 10% of NiSource’s shares.

Christie Questions FERC’s Narrow Evaluation, Investment Firm Acquisitions

Commissioner Mark Christie wrote separately to say he believed Blackstone’s involvement in Midcoast Pipelines in Texas warranted NIPSCO and Blackstone to perform a vertical competitive analysis, which they did not file. Christie said the two’s application should be considered incomplete.

“In recent years, the commission has rarely, if ever, required a vertical competitive analysis when approving section 203 applications — even where, as here, the merging entities participate in the same geographic market. The commission has relied on other evidence presented by the applicant to confirm that there are no vertical market power concerns. Although this may be a more administratively convenient approach, it ultimately does not conform to the commission’s regulations,” Christie wrote.

Christie said though he ultimately concurred with the commission’s decision, it may be time to “revisit” FERC’s policies when approving transactions — especially in the face of increasing partial acquisitions among utilities. He said he worried the motivations of investment firms run counter to public interest.

“I have previously written separately about my concerns over these partial acquisitions and what they may mean for the public interest, competition and reliability. There is an inherent tension between the profit-seeking motivations of large investment management entities and public utilities with the responsibility to provide reliable power at a just and reasonable rate,” he said. “It is the commission’s responsibility … to evaluate transactions involving these large investment management entities to determine whether they comport with the public interest. To do so… the commission must have regulations it can enforce that capture the concerns present in the types of transactions that occur today.”

Public Citizen to File Letter with FTC Over FERC Antitrust Considerations

In an interview with RTO Insider, Public Citizen Energy Program Director Tyson Slocum said he shares Christie’s frustrations with “FERC’s insistence on utilizing such a narrow approach on reviewing mergers and acquisitions.”

He said Public Citizen is “obviously disappointed” with the outcome of the docket and it plans to send a letter to the Federal Trade Commission about FERC “bizarrely” believing it lacks authority to consider violations of antitrust statutes when it decides mergers and acquisitions.

Slocum said it’s a “clear violation” of antitrust laws for Blackstone executives to simultaneously serve on the boards of NiSource and FirstEnergy, even when they’re situated in different RTOs.

“I think it’s fair to say that NiSource and First Energy are engaged in some level of commerce that should be a flag for antitrust violations,” Slocum said.

Slocum predicted a “sustained push” by private equity investors to acquire interest in utilities and “negotiate control over the board and other aspects of management.” Utilities are experiencing “financial weakness” and slumping share prices because of high interest rates, he said, making it attractive for firms to step in.

“I think we’re going to continue to see private equity firms playing a bigger role in public utilities,” he said.

Slocum said he’s also concerned such firms have “more opaque corporate structures and far less transparent public accounting” than utilities are tasked with. But he said there’s only a slim chance FERC retools its mergers and acquisitions evaluation process if commissioners begin to view the transaction trend as a problem.

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FERC OKs Extension for Oklahoma Solar Farm

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.

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NYISO Plans Early November Filing for Partial Order 2023 Compliance

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.

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Opponents to NJ OSW Project Sue BOEM To Stop Project

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.

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FERC Accepts ISO-NE Filing to Allow Storage as a Tx-Only Asset

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.

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DOE Officials Face Rocky Senate Hearing on IIJA, IRA Loans and Grants

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.

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FERC Orders Reliability Rules for Inverter-Based Resources

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.

It followed a Notice of Proposed Rulemaking last November. (See NERC Pushes Alternate IBR Standards Timeline Response to NOPR.)

“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.

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Panelists Say Focus, Fun Equally Important to GridEx

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.”

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FERC OKs Transmission Swap Between Idaho Power, PacifiCorp

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.