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November 15, 2024

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MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan

MISO Independent Market Monitor David Patton has made a final stand against the RTO’s $21.8 billion long-range transmission plan (LRTP) portfolio, asking MISO board members to order a postponement of the transmission portfolio and direct MISO to condense projects.

The appeal led multiple stakeholders to tell the MISO Board of Directors that the IMM should end his foray into MISO’s transmission planning and stick to supervising markets.

The showdown came as MISO advances its 2024 MISO Transmission Expansion Plan (MTEP 24) to its board of directors.

This year, MISO and members will vote on more than the traditional MTEP lineup. The MTEP 24 umbrella also officially includes the $21.8 billion LRTP and the $1.65 billion Joint Targeted Interconnection Queue (JTIQ) portfolio in partnership with SPP.

MISO staff have called the $30 billion collection historic.

In September, MISO’s Jeremiah Doner said even MTEP 24’s $6.7 billion of traditional local spending is a “sizable amount of investment occurring.” The traditional MTEP 24 includes 459 projects, with total lines spanning 932 miles.

Traditional MTEP 24 spending is smaller than last year’s $9.2 billion. And while a good chunk of MTEP 23 was devoted to local reliability needs, this year’s investment is driven by age condition projects and load growth.

However, it’s the second LRTP portfolio that’s soaking up all of the attention this year.

“Let me say at the outset: this is probably the least satisfying exercise I’ve taken part in. I take no pleasure in being critical of such an important process,” Patton told board members during an Oct. 30 teleconference of the System Planning Committee of the MISO Board of Directors. He added that he thinks transmission expansion is essential.

“We believe there are portfolios of transmission investment that will be extremely beneficial … but this portfolio is not that portfolio,” Patton said.

Patton said the “costly” portfolio represents a present value of $2,600 per family in the Midwest.

“Hence, it is critical that the analysis be objective, accurate and unbiased,” he said.

Patton said though he’s been raising concerns with the second LRTP portfolio for two years, MISO hasn’t addressed his fault-findings. MISO and the IMM have disagreed publicly on the LRTP often over the past several months. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops and MISO, Monitor at Stalemate over Need for $21B Long-range Tx Plan.)

Patton said he wasn’t trying to thwart a second LRTP but that he wanted MISO to develop a leaner portfolio with downsized projects.

He said MISO’s two most flawed benefit metrics are the mitigation of reliability issues and the avoided construction of new capacity MISO estimates the portfolio will deliver on. He said if those two benefit calculations are downgraded to more reasonable outcomes, the benefit-to-cost ratio of the LRTP portfolio would be anywhere from 0.4 to 0.7:1.

MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the projects’ lives through reliability improvements, production costs, new capacity that won’t have to be built and environmental benefits.

Patton has said repeatedly MISO is incorrect in assuming reliability issues in the footprint would become so dire that MISO should use its $3,500/MWh value of lost load as an indicator of savings. He said a more reasonable notion is that MISO would take operational actions to address reliability risks.

Patton also said that MISO’s capacity expansion modeling is fundamentally flawed, favors intermittent resources and doesn’t consider what resources will be built and where if MISO doesn’t build the second LRTP portfolio. Patton said if MISO tested against a but-for scenario where there is no LTRP II, the footprint “rationally” would experience more capacity development in the eastern part of the footprint versus more remote, intermittent resources built in the western portion. He said any reasonable utility would choose to build deliverable megawatts without the transmission.

Patton likened MISO’s estimated benefits to trying to convince his wife to agree to buying him a new car instead of getting brake repairs performed on his existing car through the argument that his life would be at risk.

“That’s the logic you have to adopt: What is the alternative?” he said.

Planners Defend Portfolio

Senior Vice President of Planning and Operations Jennifer Curran said Patton and MISO philosophically disagree on the need for the LRTP portfolio.

“When we think about the resource expansion, we have a different idea about the goals of our customers and what our members are trying to achieve,” she said. “Where we agree is that we definitely need to do what’s best for our customers. That’s at the forefront.”

Curran said MISO requires backbone transmission and that waiting risks reliability and leaving the system expansion to less valuable, piecemeal transmission solutions.

“We cannot wait for the certainty of resource types to build transmission,” she said.

Curran said members’ stated goals provided the thrust for the portfolio. She stressed that MISO did not overstep its role as a transmission planner and not a resource planner.

The MISO IMM’s view of LRTP benefits in the second and fourth columns, which drastically reduce the portfolio’s benefits of avoided reliability risks and avoided new build capacity | Potomac Economics

“We are talking about the highway transmission and not the side streets,” she said.

Curran said MISO probably is being conservative in the reliability benefits and likely understating the help transmission would provide during extreme weather events. She said MISO stands ready to testify to the need for the transmission in front of state regulatory commissions.

Vice President of System Planning Aubrey Johnson said that the collection of 24 projects would create a backbone of mostly 765-kV transmission across the Midwest. He said MISO’s aims with the portfolio aren’t to address one NERC criteria at a time but “reliably enable” the resource planning its members have indicated. Johnson acknowledged that goal does shift the portfolio into “uncharted territory.”

Johnson noted that MISO planners made more than 500 adjustments to capacity expansion siting based on MISO members’ counsel.

Executive Director of Transmission Planning Laura Rauch said there are almost certainly additional benefits beyond those that MISO monetized in its business case, including more reliability and efficiency value and expanded transfer capability. Rauch said LRTP II will enable the sweeping flows that help keep the lights on during heat domes, derechos and ice storms.

MISO board members withheld their opinions on the LRTP and asked mostly clarifying questions on Patton’s criticisms and MISO’s process. They did not publicly address Patton’s appeal for a pause on the LRTP approval process.

“Is there a sense of, ‘don’t build and this [capacity] will evolve?’” board member Phyllis Currie asked of stakeholders’ attitudes across the 300-plus public meetings MISO held during the development of LRTP II. She said her question “strikes at the role of MISO” as a transmission planner and keeping out of resource planning.

Johnson said stakeholders generally were supportive of MISO’s direction on planning and confirmed to MISO that the proposed lines followed their burgeoning resource plans.

Board member Trip Doggett invoked a recent Grid Strategies report that placed MISO and CAISO at the top of regional planning efforts in the country, giving each a ‘B.’ Doggett asked what MISO should do to reach ‘A’ status. Curran said MISO’s grade boils down to the LRTP not yet extending to the MISO South region.

The System Planning Committee is set to hold a vote on whether to recommend MTEP 24 along with LRTP II at a Nov. 19 teleconference.

Chorus of Support, Some Detractors and Complaints that IMM has Overstepped

Most public comments after the IMM and MISO delivered their positions provided support for the LRTP, with multiple stakeholders telling MISO board members that the IMM shouldn’t be influencing transmission planning.

Michigan Public Service Commission staffer Erik Hanser said Patton is mistaken that “market forces alone” can fill the need for transmission planning.

Hanser also said Patton “bringing these issues up month after month” is not a good use of time for the Market Monitor, who he emphasized is not a transmission monitor. Hanser said he questioned how appropriate it was for the IMM to spend so much time and attention on an area outside of his market monitoring responsibilities.

Minnesota Public Utilities Commissioner Hwikwon Ham said MISO’s long-range transmission planning allows state jurisdictions to carry out their resource planning. He also said MISO’s comprehensive transmission planning saves ratepayers money over the long run.

American Transmission Co.’s Bob McKee said it’s inappropriate for the IMM to think his opinion on planning should override those of the stakeholder community. McKee invoked the LRTP as “exactly the type of long-range planning” that FERC is requiring RTOs to engage in per Order 1920.

McKee also said that LRTP II will go a long way in addressing the “new, unforecasted, historic, large-point loads” that are cropping up on the system and are requiring several out-of-cycle transmission projects.

Natalie McIntire, of the Natural Resources Defense Council’s Sustainable FERC Project, said the IMM simply seems opposed to top-down regional planning and said MISO is leading the industry in planning. She asked board members not to entertain the IMM’s requests.

WPPI Energy’s Steve Leovy, however, seconded the IMM’s ask for MISO to test the LRTP against a future case where the second LRTP portfolio doesn’t exist. He said the additional testing from MISO wouldn’t usurp the role of resource planning or infringe on states’ rights.

“Let’s be clear: The debate we are having today is not about methodology. It’s about ideology. And it’s being driven by Dr. Patton in ways that I believe are inappropriate for his position. I believe he has abandoned his independent voice,” Union of Concerned Scientists’ Sam Gomberg said.

MISO’s Aubrey Johnson | © RTO Insider LLC 

Gomberg said it’s a “huge red flag” that Patton presented analytics showing the LRTP falls below worthwhile investment without documentation detailing his methods. MISO and stakeholders have “repeatedly suffered through” presentations on Patton’s uncorroborated numbers, Gomberg said, while Patton at times “belittles” MISO’s and stakeholders’ perspectives.

“Throw out any number you like in a public setting as long as it’s big enough to catch attention, let the media sink their hooks into it and the headline on the front-page reads: ‘IMM Says MISO Transmission Plan isn’t Worth It’ while everyone else scrambles to explain after-the-fact why this number shouldn’t be trusted,” Gomberg told board members. “When this happens, it makes yours and every state regulator’s job harder because it colors your and regulators’ ability to do the proper, objective due diligence necessary to weigh the costs and benefits of these projects.”

Gomberg said the IMM’s actions are “at best negligent and at worst a deliberate attempt to undermine the process.” He said he “believes it’s past time” for the MISO Board of Directors to “clearly and publicly” define the IMM’s role in MISO transmission planning and hold him accountable to transparency standards and analytic rigor.

“The character assassination of Dr. Patton is really unfortunate,” North Dakota Public Service Commissioner Julie Fedorchak said. “There’s a lot of opportunity between doing nothing and spending $30 billion in transmission planning.”

Fedorchak said MISO should listen to independent, third-party critiques that its LRTP business case is overblown.

“With these benefits, you could justify building just about anything,” Fedorchak said, reminding board members that North Dakota doesn’t have clean energy goals and it’s unfair for the state to shoulder a portion of LRTP costs.

Kavita Maini, a consultant representing MISO industrial customers, also said she appreciated the IMM’s request to take a hard look at the LRTP.

“We need an independent voice, and we appreciate the IMM’s efforts,” Maini said.

But Google’s Tyler Huebner said MISO’s “effective, multi-value transmission planning” is vital and serves as proof that not all members in the end-use sector agree with one another.

Clean Grid Alliance’s David Sapper said board members should “strongly” consider Google’s support since the LRTP is rooted in a future view of the grid, implying that Google should know better than most what’s to come.

ITC’s Brian Drumm said MISO assembled the second LRTP portfolio with industry-tested practices and planning tools that are crucial to maintaining reliability as the clean energy transition and load growth knock on MISO’s door.

“Now is not the time for us to slow down,” he said, endorsing the LRTP.

Drumm also said Patton’s “is just one voice” among hundreds of stakeholders who contributed to the multiyear development of the LRTP.

Great River Energy’s Priti Patel said she likewise was lending support to LRTP II. She said Great River Energy independently tested the LRTP’s business case and found that proposed lines in Minnesota best meet technical needs while minimizing impacts to communities across GRE’s electricity cooperative.

“We see this is a significant and necessary step to maintaining future reliability,” Patel said.

Xcel Energy’s Drew Siebenaler encouraged MISO and its board to proceed with the LRTP as soon as possible.

“In my professional career, I’ve never encountered a stakeholder process that has had more hours and engagement as this,” Iowa Utilities Board Member Josh Byrnes said of the journey to the second LRTP portfolio.

Byrnes said though “not everyone got what they wanted,” the LRTP has struck a good balance in planning.

“I truly believe that doing nothing is probably not a good option for us,” Byrnes said.

System Planning Committee Chair and MISO board member Mark Johnson thanked stakeholders for their perspectives.

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FERC Grants ODEC Complaint on $18M Mischarge from FirstEnergy

FERC on Oct. 29 granted a complaint by Old Dominion Electric Cooperative (ODEC) filed against FirstEnergy and PJM alleging the utility overcharged it and asking for $18.6 million in refunds (EL24-121). 

FirstEnergy’s Potomac Edison bills ODEC’s load in its territory through PJM based on information the RTO gets from the utility. The complaint alleged that FirstEnergy overcharged ODEC from July 2022 through the end of 2023 by including the load of Front Royal, Va., in the calculations when the co-op does not serve that municipality. 

The utilities tried to work out the issue on their own, but FirstEnergy wanted to resettle the entire region because other utilities were undercharged, while ODEC wanted it taken care of bilaterally. FirstEnergy also wanted to pay ODEC only when it got money back from the other entities involved, but by the time the complaint was filed, it had not received any. 

ODEC said it did not consent to FirstEnergy imposing the condition that it must resettle with all suppliers prior to providing it with refunds, FERC said. 

The complaint asked FERC to find that ODEC was mischarged and that FirstEnergy failed to meet its obligation to timely effect a financial resettlement with PJM, and to direct repayment. 

FirstEnergy argued that it was taking the proper steps to fix the mischarges and was working with the rest of the impacted entities to resettle, pursuant to PJM’s rules for resettlements. The only reason ODEC did not get any refunds was that it declined to take partial payments as the resettlement of the zone was occurring, the company argued. 

ODEC said the rules do not require FirstEnergy to resettle the entire zone before paying back all that it owes the co-op. PJM agreed with this assessment in comments filed on the dispute. 

FERC agreed that ODEC was overbilled because of the inclusion of Front Royal’s load, which led to it paying more than it owed for energy, capacity and transmission charges. 

“FirstEnergy’s action in misattributing Front Royal’s load to ODEC was a violation of the filed rate,” FERC said. “Therefore, we grant the complaint and find that ODEC is entitled to reimbursement of the overcharges. … 

“Nothing in the record supports FirstEnergy’s assertion that resettlement is required before providing a refund to ODEC. Indeed, PJM states in its answer to FirstEnergy’s answer that the PJM tariff and PJM processes do not require that FirstEnergy first resettle the entire wholesale market in its zone before refunding ODEC.” 

Nothing in PJM’s rules applies to the situation in the complaint, so FERC said it was using its discretion to direct FirstEnergy to file a repayment plan to make ODEC whole plus interest within 60 days of the order’s issuance. FirstEnergy will have to discuss the plan with ODEC and indicate in that filing whether it has agreed on a plan with the co-op or explain why that did not happen. 

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California Labor, (Possibly) Public Power to Sponsor Pathways Legislation

SACRAMENTO, Calif. — A representative of one of the staunchest opponents of past efforts to transform CAISO into an RTO said his labor union plans to sponsor the California legislation needed to implement the “Step 2” proposal of the West-Wide Governance Pathways Initiative.

On top of that, another previous objector to CAISO “regionalization” — a coalition of California’s publicly owned utilities — signaled it might sign on as co-sponsor.

“I am very happy to say that we will be sponsoring the bill in the next California legislative session to implement the Pathways proposal for the CAISO and for the California utilities,” Marc Joseph, an attorney representing the International Brotherhood of Electrical Workers (IBEW), said Oct. 30 during a panel discussion at the CAISO Stakeholder Symposium in Sacramento.

Joseph noted he’d sat on the stage at the same CAISO event eight years earlier to voice concern about the first of three attempts to regionalize the ISO through bills that would’ve transformed the California grid operator into an independent entity by eliminating the state’s role in appointing its Board of Governors.

“This would mean that all of the functions of the CAISO would be removed from California control with no idea what would happen to them, and no chance for California to go back if we didn’t like the outcome,” Joseph said. “The legislature was in effect being asked to mortgage the farm with nothing more than ‘trust us’ as collateral.”

That approach was “a particular problem” for California labor groups because the state’s renewable portfolio standard (RPS) is “anchored” in the CAISO balancing authority area, requiring that a certain portion of new renewables be built in-state and directly interconnected to that BAA.

“If the CAISO became the RTO for the West, that could mean that the balancing authority area would be the entire West, and that would mean that the RPS structure would effectively be meaningless and most of the jobs for people in California would probably be exported to other states,” Joseph said.

The Pathways proposal is different, he said, because it proposes to create a new independent “regional organization” to govern rules for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) while leaving the ISO’s BAA intact, a point Joseph and other labor representatives have emphasized previously, including in front of California lawmakers. (See Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’ and California Labor Groups Affirm Support for Pathways Proposal.)

Heading off questions about the bill’s legislative author and its specific language, Joseph jokingly said: “Cool your jets. This is still October. It’s only been 30 days since the governor finished signing the bills from the last legislative session. We are ahead of schedule, and we’ll get to all of those things in due time.”

‘This is for Real’

When Joseph told Randy Howard, general manager of the Northern California Power Agency (NCPA), that IBEW planned to sponsor the Pathways bill, Howard said his first question was, “Who’s the author?”

“And I said, ‘I think we’d be interested in co-sponsoring,’ which is a big shift for us in public power,” Howard said during the same panel.

NCPA represents 16 publicly owned utilities (POUs) in California, which are responsible for scheduling about 12% of the energy delivered into CAISO. Howard said public power’s position on previous CAISO regionalization efforts largely aligned with that of labor.

“When we’ve looked at previous proposals related to an RTO — and the legislation, similar to [Joseph], we saw many more risks than we could identify benefits. And again, once you hand over the keys to the organization, you couldn’t take them back,” he said.

Howard said that, for public power, years of regional collaboration through CAISO’s WEIM eased utilities’ distrust stemming from the Western energy crisis of 2000/01. NCPA members prefer an “incremental” approach to developing a Western market, which the Pathways proposal continues to accommodate, he said.

As nonprofits, Howard said POUs are concerned primarily about maintaining reliability while keeping costs down. And while the publics would like to own all of their resources, that’s not practical, he said, and participation in a broader day-ahead market like EDAM would provide access to a greater pool of resources at a lower cost.

“And by having this more efficient market and the market platform, we should be able to continue to add these emission-free resources and do it in a way that we can share them across the West with each other, diversify greater and try to keep the rates more affordable for our ratepayers, because that’s what we think is the most important thing,” Howard said.

Panel moderator Kathleen Staks, executive director of Western Freedom and co-chair of the Pathways Launch Committee, remarked about the progress the initiative has made in the year since it was formally launched.

“I think it has really sort of sunk in for us, [and] for the audiences that we’ve been talking with, that this is very real. This is a real proposal, and now we’ve just made it even more real,” Staks said.

Speaking a week earlier on a panel at the fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB), Staks said she was “cautiously optimistic” about passage of the Pathways bill.

Reached for comment on the floor of the symposium, Joseph told RTO Insider he sees “nothing uniquely challenging” about passing the Pathways bill compared with “any other substantial bill.”

“In fact, because there is such widespread support for it, I think there’s every reason for it to be successful,” he said. “The single most important fact is that the leading opponents to prior rounds — labor and POUs — are now potentially sponsoring,” he said.

Joseph confirmed the legislation will be introduced during the next legislative session, which begins in January.

And he reiterated the point made by Staks.

“The level of engagement is an indication that everybody recognizes this is for real.”

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EPA Announces Nearly $3B for Clean Port Equipment

EPA on Oct. 29 announced it will disburse $2.9 billion in grants to U.S. port authorities to purchase zero-emission equipment, vehicles and on-site electricity generators through its Clean Ports Program.

The agency said the funds would support the purchase of 1,500 units of cargo-handling equipment, 1,000 drayage trucks, 10 locomotives and 20 vessels, along with battery-electric and hydrogen vehicle charging and fueling infrastructure, and solar power generation. It estimates the equipment and infrastructure will prevent more than 3 million metric tons of CO2 emissions, 12,000 short tons of NOx and 200 short tons of PM2.5 in the first 10 years of operation.

EPA selected 55 state, city and county agencies across the continental U.S. and in Alaska, Hawaii and Puerto Rico. Most are shipping ports along the coasts, but the awardees also included several agencies overseeing inland intermodal terminals, such as in Dallas and Salt Lake City.

While “ports are vital to the U.S. economy,” the agency said, “the port and freight equipment responsible for moving goods including trucks, locomotives, marine vessels, and cargo-handling equipment contribute to significant levels of diesel air pollution at and near port facilities. This pollution is especially harmful to nearby communities’ health and contributes to climate change.”

“Delivering cleaner technologies and resources to U.S. ports will slash harmful air and climate pollution while protecting people who work in and live nearby ports communities,” EPA Administrator Michael Regan said in a statement.

The largest winners were Los Angeles and the Port of Virginia, which were granted more than $411 million and about $380 million, respectively. EPA said applicants “were evaluated in part on their workforce development efforts, to ensure that projects will expand access to high-quality jobs.”

The Maryland Port Administration and Department of Transportation received more than $147 million for equipment at the Port of Baltimore, where President Joe Biden spoke on Oct. 29 to celebrate the awards.

“For too long, [ports] have run on fossil fuels and aging infrastructure, putting workers at risk and exposing nearby communities to dangerous pollution,” the president said. “The new $3 billion in funding we’re delivering today will help ports all across America … strengthen supply chains, make American businesses more competitive and keep consumer prices down while slashing carbon pollution.”

Biden took the opportunity to praise state and federal efforts to clear the wreckage of the Francis Scott Key Bridge and reopen the port. “We won’t stop until the new bridge is finished completely,” he said. “Finished, finished, finished. I call on Congress to fully fund it, this year!”

The president was joined by Maryland Gov. Wes Moore, whom he said “may be the best governor in the country,” and the state’s U.S. senators, Ben Cardin and Chris Van Hollen, the latter of whom he called “Sen. Van Halen.”

“What the hell is his name? He’s new,” Biden joked after the gaffe.

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BOEM, DOD to Coordinate on Offshore Wind

ATLANTIC CITY, N.J. — The U.S. Department of Defense and Bureau of Ocean Energy Management have reached a memorandum of understanding intended to improve the collaboration of offshore wind power development proposals. 

The move is intended to address one of the frustrations common to offshore wind development and countless other endeavors: the need to work across multiple government agencies that operate independently of one another, or sometimes even at cross purposes. 

While DOD is just one of many governmental entities, it exerts a particularly strong influence on decision-making. Offshore wind development has been paused indefinitely off parts of the Maryland and Virginia coastlines because of potential conflict with the heavy military activity there. 

BOEM Director Elizabeth Klein and Brendan Owens — assistant secretary of defense for energy, installations and environment — formalized the agreement between their two agencies at the close of the first day of American Clean Power’s Offshore Windpower conference Oct. 29. 

Owens emphasized the commonality between the two agencies. 

“The other hat that I get to wear in the job that I have at DOD right now is chief sustainability officer,” he said. “So there’s a tremendous convergence of what the Biden administration is asking all of its federal agencies to do, and the work that you all are doing and the work that DOD is doing.” 

ACP CEO Jason Grumet spoke of the imperative of collaboration as developers try to unite disparate groups of stakeholders and the challenges that presents. 

“Anyone who has actually spent time in federal service knows that one of the most challenging collaborations is among federal agencies,” Grumet said. “One of the things that I think really has marked this administration has been a remarkable amount of coordination and collaboration in a whole-of-government understanding of what it’s going to take to manage and balance our energy and environmental needs.” 

Almost all power for DOD facilities comes from outside those facilities, Owens said, so the military has a direct interest in the grid from a mission capability standpoint. “If we can flex from one source to another, that gives us resilience for our mission, and that’s the reason that we view the deployment of offshore wind critically as something that needs to be accelerated.” 

But not, he said, at the expense of training and readiness. “So DOD and BOEM have worked together to identify … and avoid impacts to national security for offshore energy planning,” Owens said, “and this MOU codifies the way that we will do that going forward.” 

“The MOU helps to define and clarify roles and duties of both of our organizations in leasing and project planning processes,” Klein said. 

In a news release, BOEM said the MOU expands on a 1983 memorandum of agreement on their activities in the Outer Continental Shelf. 

The announcement flagged four key goals: 

    • find mutual solutions that support renewable energy in a manner compatible with essential military operations; 
    • collaborate as early as possible in the offshore wind leasing process; 
    • regularly communicate and exchange information at the staff and leadership levels; and 
    • determine what areas should be deferred from leasing to enable the performance of DOD activities on the OCS. 
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NV Energy Explains EDAM Choice

NV Energy’s decision to join CAISO’s Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+ was based partly on concerns that participation in the latter would “lead to substantial expenditures with limited results,” a representative of the Nevada utility said.

In contrast, NV Energy has “high confidence” that EDAM’s first-movers will stand up the market and it will have the connectivity to produce customer benefits, according to David Rubin, the utility’s federal energy policy director.

Rubin was speaking Oct. 28 at a meeting of Nevada’s Regional Transmission Coordination Task Force to give an update on the utility’s day-ahead market activities.

The RTCTF was created by 2021’s Senate Bill 448, which also requires transmission providers in the state to join an RTO by Jan. 1, 2030.

In May, NV Energy confirmed in public statements and regulatory filings that it intends to ask the Public Utilities Commission of Nevada (PUCN) for authorization to join EDAM. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)

The decision is viewed as an important victory for EDAM because of NV Energy’s central location in CAISO’s Western Energy Imbalance Market (WEIM).

Rubin showed a diagram with dark blue circles depicting balancing areas expected to participate in EDAM, including PacifiCorp, Portland General Electric, the Los Angeles Department of Water and Power, Idaho Power and the Balancing Authority of Northern California.

Expanding that footprint to include other WEIM entities would provide even greater benefits to participants, Rubin said. But even if the footprint doesn’t widen from what’s now expected, “the dark blue footprint with its connectivity should produce extensive benefits,” he said.

A Brattle Group study for NV Energy showed that footprint contains 46% of WECC’s load, 80% of the solar generation, 70% of the storage capacity and much of the wind power, Rubin said.

It projected that the utility’s annual benefits with EDAM would range from $62 million to $149 million, depending on the market footprint. In contrast, results from Markets+ participation would range from a $17 million annual loss to a $16 million gain. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.)

Stakeholder Role

Another factor NV Energy weighed in its day-ahead market decision was the role of stakeholder participation.

In EDAM, CAISO staff work to balance positions expressed by stakeholders, Rubin said, while Markets+ employs a stakeholder-led process in which staff are more passive.

Rubin said that when NV Energy participated in the SPP process, Northwest entities tended to vote as a block while Southwest entities often varied in their opinions. As a result, NV Energy was frequently outvoted, he said.

In CAISO’s process for EDAM, “staff involvement helps protect minority interests that can get overruled by SPP’s deterministic voting structure,” Rubin said.

CAISO’s process also makes greater use of written comments, he said, which allow stakeholders to more fully explain their positions. And the written comments can be reviewed by those who weren’t able to attend a meeting.

Building on WEIM Benefits

By joining EDAM, NV Energy can build on the substantial benefits it has earned through participating in WEIM since December 2015.

CAISO announced Oct. 28 that overall WEIM benefits have grown to $6.25 billion; NV Energy has seen cumulative benefits of $589 million through the third quarter of 2024.

Rubin said NV Energy’s WEIM benefits have grown appreciably as the company has gained experience in the market and its footprint has expanded. Those benefits have helped bolster NV Energy’s confidence in EDAM.

In contrast, “we have less confidence in Markets+, even if entities spend the $150 million necessary to build out the SPP design,” he said.

NV Energy expects to file a request for authorization to join EDAM with the PUCN in the second quarter of 2025. That timing will give the company time to complete its integrated resource plan filed with the commission and see how the footprints evolve for the two competing day-ahead markets.

There also may be reactions by then to PacifiCorp’s open access transmission tariff for its participation in EDAM, expected to be filed with FERC in November, as well as a potential PGE filing in January.

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Panelists Discuss Electric, Election Security Intersections

MINNEAPOLIS — With widespread security concerns over next week’s U.S. presidential election and the Canadian federal elections in 2025, panelists at last week’s GridSecCon said the institutions serving electric reliability are “absolutely critical” for ensuring the elections remain safe and secure. 

The Electricity Information Sharing and Analysis Center (E-ISAC), which co-sponsored the 13th annual conference with the Midwest Reliability Organization, decided to hold an election security panel after repeated warnings about the “complex and dynamic” threat landscape facing U.S. and Canadian election infrastructure, according to E-ISAC Vice President of Security Operations and Intelligence Matt Duncan.  

“It’s more than just a presidential election that can be influenced,” Duncan said, reminding the audience of warnings from security experts and the federal government about cyber campaigns by foreign adversaries including China and Iran. (See Agencies Describe a Year of Iran Cyber Attacks.) “We have very close races in the House and Senate and state houses across the country, and our adversaries know that.” 

The links between election security and grid security go beyond the fact that both are critically important, panelists said. Timothy Davis, senior elections cyber threat analyst at the Elections Infrastructure ISAC (EI-ISAC), observed that threat actors “use a lot of similar tactics, no matter who they’re targeting,” which means security professionals in both sectors can share their experiences to strengthen each other. 

Spencer Wood, an election security adviser for the Cybersecurity and Infrastructure Security Agency (CISA), said physical security is as important as electronic hygiene. Describing the “horrid amounts of violence and rhetoric” that he has seen directed against election workers across the country, Wood added that state officials also need to be prepared for disruptions to the grid — both deliberate and accidental. 

“There will be power outages on election day. A squirrel will decide to jump on a transformer. There will be a tree that will fall somewhere, or an accident that will happen, or at a polling location, someone will plug in a Crock-Pot, and that will be enough to trip the breakers at the polling location,” Wood said. “That’s why you … have an incident response plan. But really the … trusted source of information is the state and local election officials.” 

Davis agreed with Wood’s recommendation for incident response plans, saying he and his colleagues at the EI-ISAC “hammer those over and over again.” Knowing whom to contact — especially on Election Day — is essential to resolve issues as quickly as possible. He said electric utilities should feel as comfortable interacting with the EI-ISAC as they do with its counterpart in their sector. 

Brandi Martin, assistant director of the Energy Security Policy and Partnerships team at the Department of Energy, said utilities should be prepared to coordinate with federal officials as well. She reminded attendees that a well-organized response plan can summon responses from a wide range of organizations, as happened during the recent reactions to Hurricanes Helene and Milton. 

“We have a lot of these practiced mechanisms, whether it’s a wildfire … hurricane, or polar vortex. So on Election Day, if we have a weather event, a cyber event or a physical event, we’re ready there to stand up those coordination calls and mechanisms as well,” Martin said. 

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Gulf of Maine OSW Auction Results in Four Leases Worth $21.9M

The first-ever offshore wind lease auction for the Gulf of Maine resulted in the sale of four offshore lease areas to two developers, bringing in a total of about $21.9 million.

The auction offered eight lease areas in total, with the potential to provide 13 GW of power. (See BOEM Announces Gulf of Maine Offshore Wind Lease Sale.) The four sold lease areas could host enough offshore wind generation to power 2.3 million homes, the U.S. Department of the Interior said in the Oct. 29 announcement.

Avangrid Renewables and Invenergy NE Offshore Wind each provisionally won two lease areas, which range in size from 97,854 acres to 124,897 acres.

Avangrid CEO Pedro Azagra said the company’s leases provide for the potential development of about 3 GW of floating offshore wind.

“Securing these lease areas provides a unique opportunity to advance our growing business at a significant value and reinforces our unwavering commitment to helping the New England region meet its growing need for reliable, clean energy,” Azagra said.

“With today’s lease sale building on earlier deepwater auctions on the West Coast, the United States is truly on track to become a global leader in floating offshore wind technology,” said Anne Reynolds, vice president for offshore wind at American Clean Power.

While all commercial offshore wind farms currently under construction or in operation in the U.S. feature fixed-foundation technology, farms developed in the deeper waters in the Gulf of Maine will need to rely on floating technology.

Although floating offshore wind technology is in its early stages — the world’s largest floating installation has an 88-MW nameplate capacity — its development will be key to meeting state and federal clean energy goals, due to the limited availability of viable fixed-bottom locations.

The U.S. Bureau of Ocean Energy Management (BOEM) in August approved a floating wind research lease for the state of Maine, which eventually could provide the state with 144 MW of offshore wind. (See Maine Approved for Floating Wind Research Lease.)

The $21.9-million price tag is significantly less than BOEM’s 2022 California lease sale, which also was centered around floating technology. The California leases, which cover a smaller overall footprint than the Gulf of Maine leases, brought in $757 million. (See First West Coast Offshore Wind Auction Fetches $757M.)

The offshore wind industry’s struggles to scale up over the past two years may have cooled bidder interest in new lease areas. An Oregon offshore wind lease auction scheduled for Oct. 15 was postponed due to a lack of interest from potential bidders, while BOEM canceled a Gulf of Mexico auction planned for September. (See BOEM Postpones Oregon Offshore Wind Auction and BOEM Cancels Gulf of Mexico Wind Lease Auction.)

Avangrid’s lease areas (OCS-564 and OCS-568) are located about 34 miles from Massachusetts and feature “strong wind speeds” along with “relatively shallow waters within the limits of existing floating wind technology” and multiple potential interconnection points, Avangrid said.

While Avangrid’s lease areas are located adjacent to each other east of Massachusetts, Invenergy’s lease areas bookend the northeast and southeast corners of the wind energy area. Invenergy’s southern lease (OCS-567) is located about 25 miles east of Massachusetts, while its northern lease (OCS-562) is located southeast of Portland, Maine, about 53 miles offshore.

Reynolds specifically praised Maine Gov. Janet Mills (D) for the state’s “proactive approach to floating offshore wind technology.”

In 2023, Maine passed legislation (LD 1895) authorizing the procurement of at least 3,000 MW of offshore wind power “in proximate federal waters” by the end of 2040. The law directs the Governor’s Energy Office to submit its first solicitation to the Public Utilities Commission by July 2025, with the PUC set to issue a request for proposals in January 2026.

Massachusetts also is well located to purchase power from the Gulf of Maine areas, and the state has indicated it will need to procure at least 10 GW of power from offshore wind in the Gulf of Maine to meet its climate targets.

Developers recently broke ground on a new offshore wind terminal in the city of Salem, Massachusetts, which is located in relatively close proximity to the southern Gulf of Maine lease areas. (See Mass. Breaks Ground on Salem Offshore Wind Terminal.)

The availability of future leases in the area could be affected by the outcome of the presidential election in November, as Republican nominee Donald Trump has expressed hostility toward offshore wind. The Department of the Interior has another lease auction scheduled for the Gulf of Maine in 2028.

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Federal Judge Tosses Out Texas’ ROFR Law in Non-ERCOT Regions

A federal judge found Texas’ law instituting a state right of first refusal (ROFR) law violates the Commerce Clause and prohibited its enforcement in non-ERCOT regions, in an order issued Oct. 28. 

Judge Robert Pitman of the U.S. District Court for the Western District of Texas in Austin handed down the ruling on remand from the 5th U.S. Circuit Court of Appeals in the case of NextEra Energy Capital Holdings v. Kathleen Jackson in her official capacity as a commissioner of the Public Utility Commission of Texas. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.) 

The 5th Circuit decision also was appealed to the Supreme Court, which declined to take up the case in December 2023. (See SCOTUS Won’t Take up Texas Appeal of ROFR Law.) 

The Texas Legislature passed SB 1938 after FERC Order 1000 removed federal ROFRs but required ISO/RTOs such as MISO and SPP, which serve the parts of Texas in the Eastern Interconnection, to respect state ROFR laws. 

The law caused NextEra to lose a transmission project in East Texas that it had won in MISO’s competitive planning process and another project it had tried to buy from an incumbent in SPP’s territory.  

The Commerce Clause of the U.S. Constitution gives the federal government the power to regulate interstate commerce. State laws can get around it if they have legitimate policy reasons. But the judge knocked down all the arguments ROFR supporters brought up in the case. 

Texas claimed the law codified existing practices. But NextEra was able to build in the state prior to enactment of the ROFR law, as it did in the Competitive Renewable Energy Zone law. Another justification was to clean up statutory language after the CREZ lines were opened to out-of-state firms. The judge found that was not a valid reason to get around the Commerce Clause. 

Texas also wanted to avoid federal rate regulation, but the judge shot down that reasoning. 

“Balkanizing a state from interstate commerce is the very problem the Commerce Clause is meant to guard against … and so Texas’ desire to avoid the interstate market — and the federal regulation that comes with it — is not a legitimate local interest,” the court ruling said. 

The final reason was an alleged impact to reliability because the competitive bidding process adds time to transmission development. But SPP transmission lines that are needed quickly can get around the competitive process. And MISO does not have a competitive process for lines that are needed solely for reliability. 

“The federal bidding process does not undermine reliability by substantially delaying projects because these projects already take years to plan,” the court ruling said. “The type of transmission lines defendants are concerned about are proposed through federal regional planning bodies to promote long-term transmission development. Even without a competitive bidding process, the procedure for identifying those types of regionally planned transmission lines is time consuming.” 

Texas can ensure reliability with the PUC’s certificate process, and the regulator continues to have authority when lines are in service to ensure they are operated reliably, the judge said. 

“If those processes are insufficient to ensure reliability, then Texas could enact new laws that add reliability mandates,” the decision said. “The constitutional solution to Texas’ issue of ensuring reliability is to evenhandedly increase reliability standards, not to treat all out-of-state entities as necessarily unreliable.”

When it comes to competitive processes, FERC requires transmission planners to consider reliability. MISO found NextEra’s proposal for the Hartburg-Sabine project had adequate plans and infrastructure in place to ensure reliable operation. NextEra has a pending case before the D.C. Circuit Court of Appeals to try to get that project back, though MISO and FERC have since said it is no longer needed. 

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EPRI Launches DCFlex Initiative to Help Integrate Data Centers on the Grid

The Electric Power Research Institute has launched its “DCFlex” initiative that will explore how data centers can support the grid, enable better asset use and support the clean energy transition.

The initiative’s founding members include Compass Datacenters, Constellation Energy, Duke Energy, ERCOT, Google, Meta, New York Power Authority, NRG Energy, NVIDIA, Pacific Gas and Electric, PJM Interconnection, Portland General Electric, QTS Data Centers, Southern Company and Vistra.

DCFlex will coordinate real-world demonstrations of flexibility in a variety of existing and planned data centers and electricity markets, creating reference architectures and providing shared learnings to enable broader adoption of flexible operations that benefit consumers.

The EPRI initiative announced Oct. 29 will set up five to 10 flexibility hubs, demonstrating strategies that enable operational and deployment flexibility, streamline grid integration and transition backup power solutions to grid assets. Demonstration deployment will start in the first half of 2025 with testing running through 2027.

“One of the key areas where people are talking a lot, but not doing a lot, is the area of understanding how flexible data centers can be, and how we actually make that happen,” EPRI’s Principal Technical Executive Tom Wilson said in an interview. “And so that was the motivation.”

EPRI is a nonprofit that works to address challenges in the energy industry. The DCFlex initiative was born out of discussions at the U.S. Secretary of Energy’s Advisory Board about how it could help power data centers. EPRI spoke with 50 experts from the power industry and the data center industry, Wilson said.

Data centers can respond to signals in the grid in two ways — some of their computational tasks can be shifted around in time and to other data centers, and backup power generation at the facilities can be used instead of the grid, Wilson said. Diesel generation dominates their backup power now, but cleaner options more regularly could respond to grid signals without violating state air permits.

“In terms of computational flexibility, I’d say, you know, if you’re at an ATM trying to get money out, and you get the answer that you can’t get your cash until the electricity prices are lower or there’s more electricity available, you won’t be happy,” Wilson said. “And so, there are a lot of functions of data centers that you do have to have real time. Basically the customer-facing things that data centers do. Other things like indexing the web and activities like that are potentially more flexible in where they occur and when they occur.”

The customer-facing aspects of artificial intelligence also need to be ready for use whenever, but AI models require training, and that energy-intensive process can be shifted in time, Wilson said.

Google, for example, has shifted computing demand to where cheap, clean power is available at its different data centers for the past five years, he added.

“At Google, we see this moment as a generational opportunity for the public and private sector to work together to meet energy demand responsibly and unlock significant benefits for people, the economy and the planet,” Google’s Global Head of Energy Market Development and Innovation Caroline Golin said in a statement. “Through the leadership, expertise and convening power of EPRI, DCFlex will be an important collaboration vehicle to align our common goals, as we work together to build a stronger electrical grid for all.”

Data centers have helped transform the demand for power. The U.S. had flat growth for roughly two decades, but with data centers being added in the hundreds of megawatts, reshoring of industry and efforts to electrify other uses of energy, that has changed dramatically in the past year, Wilson said.

It used to be easy to plug a data center into the grid, but the growing demand has slowed the process. In 2022, Dominion put a moratorium on new connections in its territory, which includes the largest concentration of data centers in the world, called Data Center Alley in Loudon County, Va., Wilson said.

A 500-MW data center is equivalent to tens of thousands of homes being added to the grid much more quickly than more granular demand growth from an expanding population or a growing economy. Flexibility can help the grid absorb major new loads more quickly.

“In many cases, if you have transmission issues, it may just be that I can provide the power you want for 350 days a year,” Wilson said. “For 15, I can’t guarantee it for every hour in those days because of congestion, peak temperatures or higher, low — different issues. And if you have that response, is there a way to get around providing that powerful 15 days for the data centers in order to connect it now?”

When it comes to data flexibility, being able to dial back the demand from a 500-MW data center offers a significant source of demand response for the grid, he added.

“Or if it’s able to turn on backup generation and take its load entirely off the grid, that’s a huge amount of capacity that can come online,” Wilson said. “Historically, we’ve seen this with aluminum smelters and other large industry right where they’ve traditionally gotten a phone call that said, ‘can you guys turn off these hours, these days?’”

Another key is better planning around when and where data centers want to connect to the grid, said Wilson. It takes time to stand up a new data center.

“Better coordinating those ramp up schedules is really important for an understanding where both parties really are in terms of their needs and ability to respond,” Wilson said. “Because, you know, if you’re talking a gigawatt data center or 500-MW data center that’s a large amount of load, and it can be in over eight years or three years or two years. It makes a big difference.”

Constellation, which has worked with Microsoft to reopen a Three Mile Island nuclear plant to serve a Microsoft data center and has discussed co-locating data centers at its other nuclear plants, welcomed EPRI’s initiative.

“Data centers are integral to our daily lives, economy and national security,” Constellation CEO Joe Dominguez said in a statement. “Our energy system is built to handle the extreme demands of our hottest summer days and coldest winter nights but is often underutilized. The real challenge isn’t a lack of energy for data centers but managing the peak demand hours. The ability of data centers to flex during these critical periods is crucial.”