Search
December 23, 2024

Posted on

MISO Estimates Solar Fleet will be 12 GW by Winter’s End

THE WOODLANDS, Texas — MISO expects its in-service solar capacity to grow to 12 GW by the end of winter, a 50% increase over its existing fleet.

Speaking during a meeting of the MISO Board of Directors’ Markets Committee on Dec. 10, Executive Director of Market Operations JT Smith said MISO anticipates developers will finish about 4 GW of new solar generation before March hits. “That’s three times more than what we had last winter,” Smith said.

The RTO’s latest solar peak of 8 GW occurred Oct. 16.

Smith said MISO’s solar fleet even now is significant enough that the grid operator notices diurnal output patterns, with a steeper ramp requirement in the evenings.

He said members in the footprint are set to add additional 4 to 7 GW of solar generation by the end of 2025 as renewable developers bring some of their approved solar farms online.

“Next winter, we might be talking about 20 GW of solar,” Smith said.

Carrie Milton, of MISO’s Independent Market Monitor, told board members that over the upcoming winter, the RTO could experience ramping needs as high as 12 GW during the period of 3-7 p.m. She said MISO must work diligently to manage more “extreme” ramping needs.

Milton said over two instances in the fall, MISO experienced shortage intervals where prices spiked to the $3,500/MWh value of lost load (VOLL). She said in one case, generation was powering down faster than load was dropping in the evening and in another, renewable energy output fell faster than forecasted.

Milton told MISO and its board that “improved ramp management will be key,” especially as the RTO filed to increase its VOLL to a $10,000/MWh cap. “That’s going to be much more impactful,” Milton said of the higher rates.

Monitor David Patton advised MISO to expect an influx of battery storage to enter its interconnection queue soon. “Batteries are going to be increasingly economic in this environment,” he said.

MISO leadership reiterated to its board that though winter on the whole shouldn’t cause strife in the operations room, it’s preparing for at least a few challenging days.

MISO is entering winter with a 131-GW planning reserve margin requirement but a 100-GW probable demand and a 107-GW high-demand scenario. (See MISO Says Comfortable Wintertime Margins Likely in Store.) The RTO isn’t issuing serious warnings over the upcoming cold weather but isn’t ruling out a widespread freeze or snowstorm.

“We can have a mild winter — and we have the past three to five years — but you can have those days, three sigma, four sigma days that can cause tremendous damage,” MISO CEO John Bear warned.

“Each year, it’s almost predictable that something is going to happen,” Milton agreed. But Milton said even in the IMM’s analysis of worst-case winter conditions, MISO still should experience a 2% margin.

Smith noted that MISO’s past few winter storms with precarious operations have occurred over long holiday weekends. The February 2021 winter storm occurred over Washington’s Birthday, and the December 2022 winter storm occurred over Christmas.

Smith joked that he hoped MISO’s next bout of serious winter weather shows up “Tuesday on a non-holiday weekend” so members can contract adequate natural gas ahead of time.

Otherwise, MISO exited a “wholly unremarkable” fall, Smith said, with a 106-GW peak occurring Sept. 19 and short of its projected 108-GW peak.

Milton noted that over the fall, congestion costs were dramatically lower in the northwest portion of the footprint as drought conditions in Manitoba eased and MISO began receiving power exports again instead of importing to the province. She also said that SPP further improved MISO’s congestion position by implementing a remedial action scheme for the Charlie Creek flowgate in North Dakota. Milton said the scheme, which involves SPP cutting load in their footprint to avoid exacerbating congestion, reduced costs of the constraint by 95%.

The Charlie Creek flowgate has been a contentious issue between MISO and SPP since 2023, when a cryptomining facility began operations in an SPP load pocket and exacerbated congestion. (See MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management.)

Posted on

MISO Board Endorses $21.8B Long-range Transmission Plan

THE WOODLANDS, Texas — The MISO Board of Directors has approved a landmark, 24-project, mostly 765-kV collection of lines and facilities for the RTO’s Midwest region at a cost of $21.8 billion.

The board voted unanimously in favor of the RTO’s second-ever Long-Range Transmission Planning (LRTP) portfolio during its Dec. 12 meeting.

MISO estimates the benefit-to-cost ratio of the portfolio to be between 1.8:1 and 3.5:1 over the first 20 service years of the projects, owing to superior reliability, production costs, avoided construction of new capacity and environmental benefits. The grid operator’s planners emphasized that the benefit values are intentionally on the conservative side. (See $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.)

MISO Chief Strategy Officer Andre Porter said the portfolio will allow for “additionally optimized buildout” of generation desperately needed on the system.

Speaking for MISO’s transmission owners, ITC Holdings’ Brian Drumm said the second LRTP represents the “single largest transmission portfolio in the history of the United States.” He told the board that the “765-kV regional backbone will significantly increase the MISO Midwest’s ability to facilitate generation fleet transition, accommodate load growth, and successfully withstand increasingly frequent and severe weather events.”

Sustainable FERC Project Senior Advocate Natalie McIntire called the portfolio “historic” and said the lines will further states’ clean energy goals. “These projects will serve customers for more than 40 years. We’re all going to benefit from them,” McIntire said.

John Liskey, general counsel for the Citizens Utility Board of Michigan, said he spoke on behalf of MISO’s consumers advocates when he applauded the RTO’s development of the portfolio.

Two days before the vote, the governors of Illinois, Michigan and Minnesota wrote to applaud MISO for developing the portfolio and urged the board to accept it.

“For years, we have advocated for MISO to take a long-term view in resource planning and to engage states and diverse stakeholders on the development of a robust and long-range transmission system that ensures cost-effective, reliable power for our residents and businesses with the flexibility to accommodate a diverse resource mix,” wrote Minnesota Gov. Tim Walz, Michigan Gov. Gretchen Whitmer and Illinois Gov. JB Pritzker. “This work is more important than ever as the region works to grow our economies and prepare for load growth from data centers, advanced manufacturing, electric vehicles and more.”

Caveats and Criticism

“This is a monumental moment in our shared history,” said Yvonne Cappel-Vickery of the Alliance for Affordable Energy, a Louisiana consumer advocacy nonprofit. But she also said MISO South desperately needs comparable planning, which is years away by MISO’s schedule. The longer MISO waits to propose transmission in the South, which she said contains MISO’s poorest regions, the longer ratepayers are deprived of the economic benefits that transmission brings, she said.

North Dakota Public Service Commissioner — and U.S. Representative-elect — Julie Fedorchak said she did not agree with MISO and stakeholders shutting out the Independent Market Monitor’s criticisms of the portfolio and putting “the IMM in a box on what he can and cannot comment on.”

Monitor David Patton had argued the LRTP portfolio is too expensive and its benefits far-fetched. Patton has said repeatedly that the capacity expansion MISO envisions through the early 2040s and the portfolio it is based on is “extremely unrealistic.” Patton insists his analysis shows the portfolio’s benefits fall well short of covering costs.

Several stakeholders countered that the Monitor should concentrate on markets and that his opinions on transmission planning are an overreach.

MISO argues it based its outlook on the resource plans its members have communicated and that it is not its place as an RTO to test the LRTP portfolio against an imagined, alternative resource expansion.

Prior to approval, the board had been mum in public meetings as to its level of support for the portfolio or whether they viewed the Monitor’s criticisms of the portfolio’s estimated value as legitimate.

The Union of Concerned Scientists’ Sam Gomberg asked MISO to formally define the Monitor’s role, including the boundaries of his role in transmission planning. Gomberg said if MISO decides to allow the Monitor to influence its transmission planning process, it should hold it to a “reasonable standard of analytic transparency.”

ACORE Webinar

Hours after board approval of the massive portfolio, the American Council on Renewable Energy hosted a webinar called “Midwest Does it Best.”

MISO Director of Cost Allocation and Competitive Transmission Jeremiah Doner said the 765-kV lines are a “major leap forward.” MISO has very few 765-kV lines today, he said, and the expansion will position MISO to handle load growth, fleet transition and more commonplace weather extremes.

“We saw we really needed to make that step to 765 kV,” Doner. He added states’ resource planning took center stage in MISO’s transmission planning, and the lines were not charted with any political objectives in mind.

Clean Grid Alliance Executive Director Beth Soholt said the approval means members can “build the grid that’s going to incorporate what the states are going to do.”

Tyler Huebner, of Google’s Energy Market Development Team, said the investment is “a big down payment” for companies, like Google, with ambitious climate goals.

Indiana ROFR Reversal Complicates Project Assignment

“For the first time in 18 months, I don’t have a map of projects to share with you; I don’t have a study process to discuss. We’ve come a long way,” Vice President of System Planning Aubrey Johnson told the board’s System Planning Committee on Dec. 10.

MISO planning leads Aubrey Johnson and Laura Rauch spearheaded the LRTP effort. | © RTO Insider LLC

Johnson said about $7 billion of the $21.8 billion portfolio will be open to competitive bidding. However, the figure does not account for the fresh court injunction against Indiana’s right of first refusal law.

U.S. District Court for Southern Indiana Chief Judge Tanya Walton Pratt blocked the law benefiting incumbent utilities that had been in effect for about a year and a half. Chief Judge Tonya Walton Pratt on Dec. 6 issued a preliminary injunction against Indiana’s House Enrolled Act 1420, which allowed incumbents first crack at the opportunity to build transmission projects planned by MISO. (See New Law Expands Indiana ROFR Law for Transmission Buildout.)

Competitive transmission developer LS Power sued the Indiana Utility Regulatory Commission, arguing the state violated the U.S. Constitution’s Commerce Clause by treating in-state developers differently out-of-state developers.

Pratt agreed with that argument.

“HEA 1420, though not a complete ban on out-of-state transmission owners, erects a barrier to the interstate electric transmission market by limiting who can compete for new construction projects in Indiana,” Pratt wrote. “The right of first refusal in favor of Indiana incumbents runs contrary to the Supreme Court’s admonition that ‘states cannot require an out-of-state firm to become a resident in order to compete on equal terms.’”

Johnson said the uncertainty over whether LRTP projects in Indiana will be open to competitive bidding did not affect the board’s ability to approve the portfolio. MISO Counsel Jacob Krause later added that the RTO’s legal team is analyzing the court ruling to determine who can build LRTP projects in Indiana. He agreed the temporary injunction did not impede the board’s ability to vote on the package.

Doner said MISO is indifferent as to which companies construct the LRTP lines but wants them finished in a timely manner.

No LRTP Planning in 2025

MISO board members will evaluate a third major transmission portfolio at the end of next year because the RTO announced it will take a break from long-range planning over 2025 to revamp its three, 20-year future scenarios it uses to evaluate system needs. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.)

“The futures have already gone stale,” Drumm said during the ACORE panel.

When MISO returns to LRTP work in 2026, the next portfolio again will prescribe transmission for the Midwest, leaving the South’s long-range needs unaddressed for the next few years.

The LRTP this year overshadowed MISO’s prescribed $6.7 billion of traditional spending as part of its annual Transmission Expansion Plan, which also was approved (See $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.) The board also greenlit the $1.65 billion Joint Targeted Interconnection Queue transmission portfolio developed in partnership with SPP.

In total, the board sanctioned more than $30 billion in transmission investment.

Posted on

GE Vernova, ExxonMobil Address Data Center Demand with Gas

Two major operators in the natural gas and power sectors say they are moving to meet data center power demand with new natural gas generation capacity.

GE Vernova executives reported during a Dec. 10 investor update presentation that its gas turbine business is surging, with 9 GW of manufacturing slots contracted in the past 30 days, largely due to hyperscaler demand.

ExxonMobil said in its corporate plan update Dec. 11 that it plans to build a large behind-the-meter generation facility that would burn natural gas the company produces and then sequester most of the resulting CO2 emissions in permanent underground storage. It said its facility would be built independent of existing grid infrastructure and independent of utility timelines and therefore will be faster-moving than alternatives available to power data centers.

GE Vernova Growth

“I’ve been involved in the gas business for 12 years,” GE Vernova CEO Scott Strazik said during the investor update. “I can’t think of a time that the gas business has had more fun than they’re having right now.”

GE projects 20 GW of gas equipment orders per year through 2028. The 9 GW of manufacturing slots it contracted in the past 30 days are priced higher than previous orders, and December bids are higher still.

“We’re barely scratching the surface of what that means for this company,” Strazik said. “We’re already into selling the last of our slots for gas in ’28 right now. We’re already selling transformers and switch gear into ’28 and ’29 very quickly.”

GE Vernova is gradually increasing gas turbine production capacity at existing factories. Even so, Strazik said the company’s output already is contracted through most of 2028.

Strazik noted that manufacturing slot reservations are not orders. Many of the projects in development have not secured air permits or engineering, procurement and construction contracts yet, and some of the prospective customers have no experience with the complexities of setting up a power plant.

But the reservations come with a firmly fixed price, hefty cash deposits and financial backstops, he said. The company expects they will begin to be converted to orders in mid-2025, but “as a bridge to secure those slots, we’ve gotten paid money now, while they work through the rest of their process.”

These reservations, Strazik said are “all in the U.S. tied to the load growth in the U.S., in the best indicators yet in our gas orders book — or what will be our gas orders book — of serving the hyperscaler demand associated with AI.”

Strazik compared the demand ramping up now with the aftermath of World War II, when nations rebuilding and modernizing needed to create a bigger, better grid. GE Vernova’s corporate forebear, General Electric, played a huge role in making that happen, he said, and is poised to do the same here.

That said, he is not rushing to increase gas turbine production capacity beyond the expansion already underway — from 55 units a year to 80 — because he does not want to spend money to accommodate what may turn out to be a short surge in production. He wants a sustained order book stretching out six to 10 years. If that happens, and more manufacturing capacity is needed, the company will consider adding it.

The investor update was delivered after the stock market closed Dec. 10 and contained mostly good financial projections — a marked contrast to the multiyear slide General Electric endured before the conglomerate dissolved into its component businesses.

GE Vernova’s stock price closed 5% higher in heavy trading Dec. 11 and is 145% higher than when it debuted April 2, 2024.

ExxonMobil’s Different Approach

Many companies in the technology sector are pressing for emissions-free power to burnish their environmental credentials. But wind and solar can’t provide the 24/7 baseload power that data center operations demand.

New-build nuclear generation potentially could meet this need, but it has many hurdles to clear before becoming a viable, scalable option, a decade or more in the future.

Natural gas burns more cleanly than other fossil fuels and it can serve as a baseload or peaker. Also, the United States produces far more of it than any other country. ExxonMobil is one of the largest U.S. producers of natural gas and GE Vernova is the leading supplier of equipment to turn it into electricity.

ExxonMobil’s data center plan comes with some caveats — the fully islanded power plant would require additional investments by the company and its partners, and the carbon capture and storage project would need government permits.

But the oil supermajor said it already has agreed to transport and store up to 6.7 million tons of captured CO2 per year for customers in the steel, ammonia and hydrogen industries.

Data centers are the next step — ExxonMobil said it believes energy-intensive AI could account for up to 20% of the CCS market in 2050.

Planning is underway for the first-of-its-kind project announced Dec. 11, with the company well into the front-end engineering design and engaged with potential customers.

The intent is to burn low-carbon-intensity natural gas and capture more than 90% of CO2 emissions, though it also might use higher-carbon-intensity gas.

The off-grid nature of the facility would free it from the interconnection and transmission constraints that are hampering U.S. energy development.

“We’re in a unique position to provide low-carbon power at large scale on a very competitive and accelerated timeline,” Dan Ammann, president of ExxonMobil’s Low Carbon Solutions business, said in a news release.

The company did not disclose details such as the location, cost and capacity of this facility.

The clean energy and net-zero commitments of Big Tech companies have not stopped them from using fossil power. Instead, they may offset the gas with clean energy capacity.

Entergy Louisiana, for example, seeks to build three gas plants with a combined output of 2.3 GW and cost of $3.2 billion to power a $10 billion facility that will be Meta’s largest data center.

Meta, which has a self-imposed goal of net-zero emissions across its operations and suppliers, has committed to matching 100% of the gas-fired electricity used there with clean generation elsewhere.

Nonetheless, this and similar arrangements result in construction of expensive fossil infrastructure with an operational lifespan and cost-recovery period potentially stretching decades.

Posted on

Parties Lobby FERC for Preferred Paths Forward on Co-location

Supporters of co-locating large loads with generators want FERC to move quickly on rules on the construct, while opponents urged the commission to take its time and make sure it gets the rules right, according to comments filed ahead of a Dec. 9 deadline (AD24-11). 

The commission had solicited comments on a technical conference held in November on the issue. (See FERC Dives into Data Center Co-Location Debate at Technical Conference.) 

Google told FERC that it is not seeking to avoid paying its fair share of the costs of major new data centers, but that rapid demand growth and slow additions of new supply means the option should be preserved. 

“At Google, we … want to partner in building systems that will support the nation’s growing needs in a reliable, secure and cost-effective manner,” the firm said. “Co-location arrangements should not be a means to bypass paying for necessary infrastructure, but instead a mechanism to advance well-coordinated and deliberate planning and include appropriate mechanisms to ensure other grid customers are insulated from the impacts of any co-location arrangement.” 

Co-location can help timely integrate new load and generation, but it is not a substitute for the broader infrastructure investment needed to support load growth, Google said. Ideally, the company wants to use co-location with new generation, but interconnection backlogs have delayed many of those projects. 

Another major issue with the growth of data centers is load forecasting uncertainty. Google suggested that FERC require large load developments to make material, upfront commitments before they are included in RTO forecasts. 

“For example, as part of their load forecast verification processes, RTOs could require [utilities] to verify that all new large loads have made material upfront financial commitments to be included in load forecasts that underpin near-term (e.g., five-year time horizon) generation and transmission planning tools,” Google said. 

The same day the tech giant filed its comments with FERC, it announced a partnership with Intersect Power and TPG Rise Climate to build new data centers co-located with new generation. (See Google Aims to Co-locate New Data Centers with Clean Power Projects.) 

“The partnership will pair new data center facilities with new carbon-free energy resources, with both the load and generation grid-connected and planned in collaboration with relevant grid operators,” Google said. 

Intersect also filed comments, saying FERC’s approach needs to create clarity but avoid impairing future industries and innovations in setting some rules of the road. 

“The absence of standard rules, practices and procedures for integrating co-located with new and existing generation (including tariff language and, where necessary, pro forma interconnection agreements and procedures) means co-location configurations must go through a laborious, unpredictable, semi-discretionary process to interconnect,” Intersect said. “This risks losing the interconnection and transmission efficiencies co-location can otherwise offer.” 

FERC should support fully isolated, co-located load by recognizing that no transmission rate responsibility is appropriate because to do otherwise would eliminate incentives for large loads to limit their impact on the rest of the grid, Intersect said. However, co-location setups will vary, and FERC should ensure its rules are flexible. 

PPL has one of the first co-located loads on its system, in the form of an Amazon data center at Talen Energy’s Susquehanna nuclear generating station, and it said FERC needs to move quickly to set some rules of the road. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

“The easiest solution to the dilemma of behind-the-meter co-located load would be to prohibit it,” PPL said. “If the rule was simply that any interconnected load must be served by a public utility, the location of the meter would be irrelevant. Load would likely still co-locate with generation to take advantage of the high levels of reliability on the high-voltage system and to avoid costly transmission upgrades, but that would not itself cause additional reliability or cost-shifting concerns.” 

FERC likely cannot prohibit co-location because it lacks direct jurisdiction over customers, with Pennsylvania law allowing the Susquehanna deal to go forward, the company said. 

“Although these loads are end-use customers, and not directly subject to the commission’s jurisdiction, they can reach a gigawatt or more in size,” PPL said. “This is two orders of magnitude bigger than the largest retail loads typically interconnected with the electric grid and … more akin to medium-sized cities appearing rapidly on the system.” 

Dominion Energy’s main utility serves one of the largest data center markets in the world in Northern Virginia and also owns a merchant nuclear plant, the Millstone facility in Connecticut. 

“Proper planning and monitoring must be in place to facilitate co-location configurations,” Dominion said in its comments. “Due to their significant size, co-located loads can cause operational challenges and impact reliability in certain scenarios.” 

If the load drops off while the generator is connected to the grid, it will push hundreds of megawatts onto the system, requiring an operational response, or the generator could turn off and lead to a sudden boost in demand, the company said. The impacts on transmission and resource adequacy need to be studied. 

“Ideally, the commission should provide the option and flexibility to large load customers to co-locate with new generation,” Dominion said. “Co-located load with new generation configurations, if structured properly, can provide several benefits to the grid.” 

Constellation and Exelon’s Dispute Continues in Comments

Constellation Energy and Exelon have been very active in the debate about co-location. The two firms used to be one, so all of Constellation’s nuclear plants where it has explored co-location are in Exelon’s utility territories.  

Constellation urged FERC to move quickly and adopt new rules. 

“The rules for connecting and serving new large load such as data centers will significantly impact whether those customers come to PJM, another region or another country, who bears the cost of connecting and serving that load, and how resource adequacy will be ensured,” it said. 

One thing both sides of the argument agreed on at the conference was that resource adequacy underlies co-location. Constellation argued that the challenges of serving new load are the same regardless of whether it locates behind a generator’s meter or on the grid. FERC can do a rulemaking or policy statement to deal with the issues, but Constellation urged it to quickly act on a complaint it filed seeking changes to PJM’s rules. (See Constellation Complaint Seeks Formal Data Center Co-location Rules.) 

“Opponents of prompt action likely will argue that enabling fully isolated co-located load configurations would impair reliability or raise prices for others,” Constellation said. “As was clear from discussion at the technical conference, concerns regarding the impact of load growth on reliability and prices are the same regardless of the new load’s choice of configuration.” 

Constellation has argued that the co-location deals it is pursuing will not use the grid, but it said it was open to FERC looking into whether such deals still have the customer using some grid services. 

“If the commission believes that PJM’s current rules on netting, generator payment for ancillary services or other [matters] must be changed, those discussions should be conducted and resolved as quickly as possible to provide regulatory certainty,” Constellation said. 

Exelon filed joint comments with East Kentucky Power Cooperative and Southern Maryland Electric Cooperative, which also argued for prompt action. 

“These generation units are supported by our electric grid — a network that is relied on, and has been paid for over many decades, by the American public,” they said. “Broad consensus emerged during the technical conference that the parties to co-location arrangements should pay their ‘fair share’ of that grid and the costs of keeping it safe and reliable, without unreasonable cross-subsidization by the consumers who have long supported it.” 

The issues around artificial intelligence and its future go well beyond FERC’s purview and will also need to involve the White House and other agencies, they said. 

“New policies providing special treatment exclusively for co-located data centers are not needed for the data center industry to thrive — whether in the name of national security or otherwise,” they said. “In contrast, promoting a regulatory environment that hastens the development and interconnection of generation and transmission infrastructure for all end users, rather than a small subset, will benefit domestic development of AI and other industries that have a national security interest.” 

Two Consultants with PJM Experience Weigh in

Suzanne Glatz and Abraham Silverman, consultants who worked in and around, respectively, PJM for years, filed comments arguing that data center co-location deals might appear the same as other load interconnections from an engineering perspective, but not a regulatory or transmission cost allocation perspective. 

Generators do not pay for transmission service, while grid-connected loads with on-site generation do, and they have vastly different rate impacts. 

“To be fully isolated, a facility must disconnect from the grid,” they said. “Some commenters have suggested a co-location load is fully isolated when protection devices are installed to prevent the load from taking power from the grid. This does not constitute isolation and does not change the fact that the co-location configuration is connected to the grid and using the grid. Otherwise, a generator would simply isolate from the grid and serve the load directly.” 

They suggested FERC put such arrangements in the same processes that account for other changes in system load to ensure that they are treated equally. Another option would be to put co-location deals in the interconnection process. 

“This option requires updating the interconnection process,” they said. “For example, the current interconnection processes do not, and are not designed to, account for behind-the-generator-meter-connected load. New tariff requirements would have to be developed in order to incorporate the additional data needed to account for addition of the customer load and other electrical parameters of the customer facilities needed to perform reliability studies.” 

Posted on

NERC Standards Committee Preparing to Welcome New Members

At their final meeting of 2024, members of NERC’s Standards Committee said goodbye to several departing colleagues while arranging the committee’s business for the coming year.

Chair Todd Bennett of Associated Electric Cooperative Inc. thanked all the members whose terms expire at the end of December, with particular praise for his predecessor as chair, Amy Casuscelli of Xcel Energy.

“I’ve been in the room quite a bit with her [over] the past eight years with the Standards Committee,” Bennett said, listing Casuscelli’s “two terms as chair, one term as vice chair and a couple years as a general committee member.”

“Thank you, Amy, for your service, and thank you to all the members who are exiting,” he continued.

Along with Casuscelli, the following members’ terms expire at the end of 2024:

    • Charles Yeung — Southwest Power Pool
    • Vicki O’Leary — Eversource Energy
    • Patti Metro — National Rural Electric Cooperative Association
    • Jim Howell — Treaty Oak Clean Energy
    • Justin Welty — NextEra Energy
    • Venona Greaff — Occidental Chemical
    • Philip Winston — Retired
    • William Chambliss — Virginia State Corporation Commission
    • Steven Rueckert — WECC

To fill their seats the committee is holding an election, which ends Dec. 13. Yeung, O’Leary, Metro and Greaff were nominated for reelection in the nomination period that ran from Oct. 21 to Nov. 12 and are unopposed in their segments, as were John Martinez of FirstEnergy, who was named to succeed Casuscelli; Josh Hale of Southern Power, who will replace Howell; and Daniela Cismaru of Alberta’s Market Surveillance Administrator, nominated in Chambliss’ segment.

Segment 6, representing electricity brokers, aggregators and marketers, has three nominees to succeed Welty: Sean Bodkin of Dominion Energy; Richard Vendetti of NextEra; and Jennie Wike of Tacoma Power. For this segment, the recipient of the most votes will serve a full two-year term replacing Welty, while the runner-up will serve out the remaining term of Con Edison’s Peter Yost, who was to have served until the end of 2025 but stepped down from the SC earlier this year due to retirement.

Segments 8 (small electricity users) and 10 (regional entities), which received no nominations, will remain vacant until special elections are held in 2025, according to Dominique Love, standards developer and project manager at NERC.

The SC also seeks nominees for its Executive Committee, which, under the SC’s charter, consists of the chair and vice chair (respectively, Bennett and Troy Brumfield of American Transmission Co.) with three to five segment members elected by the full SC. SCEC members meet between regularly scheduled SC meetings to conduct SC business.

EC members cannot represent the same industry segments as the chair and vice chair; Bennett previously represented Segment 3, while Brumfield was from Segment 1. Nominations will be accepted through Jan. 6. The SC will elect EC members at next month’s meeting, currently scheduled for Jan. 22.

Only one standards action came before the committee at the meeting: a standard authorization request (SAR) from the drafting team for Project 2023-09 (Risk management for third-party cloud services).

The SC authorized the first SAR for the project a year ago and appointed the drafting team in July. The project’s remit is to “establish risk-based, outcome driven requirements that align cloud services with other third-party resources already used for CIP [critical infrastructure protection]-regulated systems” so that utilities can take advantage of the efficiency and resiliency potential of cloud services while reducing risk as much as possible.

Since their first meeting in August, team members have reviewed industry comments on the initial SAR and revised it to address stakeholder concerns. The changes to the SAR they submitted at the meeting include “allowing flexibility” as to whether to draft a new standard or revise existing standards, allowing the team to use additional reference documents and “defining a scope while allowing room for the team to address the language in the way they see fit.” The SAR passed unanimously.

Posted on

Puget Sound Energy Signs on with North Plains Connector

Puget Sound Energy has become the latest utility to stake a claim in the North Plains Connector, a 420-mile transmission line from central North Dakota to southeast Montana. 

PSE signed a nonbinding agreement with Grid United’s North Plains Connector LLC to buy 750 MW of transfer capacity on the 3,000-MW line — a 25% share. Financial terms weren’t disclosed for the deal, announced Dec. 9. 

Grid United, a competitive transmission developer, is partnering with Minnesota-based energy company ALLETE to develop the North Plains Connector. The project is billed as the first high-voltage direct-current (HVDC) transmission link among three regional energy systems: MISO, SPP and the Western Interconnection. 

ALLETE will pursue up to 35% ownership of the $3.2 billion project and would oversee the line’s operation, under an agreement with Grid United announced in December 2023. The North Plains Connector is expected to start operations in 2032. 

In May, Portland General Electric announced a nonbinding agreement with Grid United and ALLETE in which PGE is expected to hold a 20% ownership share of the project. 

That was followed by Avista’s announcement in November of a nonbinding agreement for 300 MW of transfer capacity, or a 10% ownership share. Avista Utilities provides natural gas and electric services to customers in eastern Washington, northern Idaho and parts of Oregon. 

Grid United will continue to fund the development of the North Plains Connector. PSE and PGE would invest when regulatory approvals and permits are in place. Avista would invest when the project is operational. 

Grid Benefits

The North Plains Connector will run between endpoints near Bismarck, N.D., and Colstrip, Mont. The line of up to 525 kV will be open to all sources of electric generation. 

The project is seen as a way to reduce transmission congestion while allowing rapid sharing of energy resources across a vast area with diverse weather patterns and in different time zones. 

The transmission line “will play an important role in enhancing the reliability and resilience of the Western grid,” Josh Jacobs, PSE’s vice president of clean energy strategy and planning, said in a statement. “It will be a critical link connecting PSE and its customers to new markets that can provide needed resource diversity to aid in the clean energy transition.” 

And after it’s built, the transmission line is expected to promote energy production in Montana and North Dakota. 

The project got a boost in August with the award of a $700 million Grid Resilience and Innovation Partnerships (GRIP) grant from the U.S. Department of Energy to the Montana Department of Commerce. The project began the National Environmental Policy Act (NEPA) process for federal permitting in October. 

Grid United and ALLETE first announced plans for the North Plains Connector in early 2023. (See Transmission Project Would Span Across Interconnection Divide.) 

A study by Astrapé Consulting found that the North Plains Connector could unlock 3,550 MW of capacity across MISO, SPP and the Western Interconnection. The capacity benefit represents the amount of additional demand that could be served without degrading reliability standards. (See Study: Significant Benefits for Merchant Tx Line.) 

The study modeled the North Plains Connector as two 1,500-MW HVDC lines connecting SPP and MISO to the Western grid. Results were released in June. 

Kris Zadlo, Grid United’s president and chief technical officer, said at the time that the study could encourage deeper analysis of the benefits of interregional transmission projects.  

“By shedding light on how grid-connecting projects like NPC [North Plains Connector] enhance reliability and reduce the risk of power outages, we can build a better connected, more resilient grid for the future,” Zadlo said in a statement. 

Posted on

Google Aims to Co-locate New Data Centers with Clean Power Projects

Google says it is tackling the challenge of powering its hyperscale data centers with a new partnership aimed at ensuring that when future centers come online, they will be co-located with the carbon-free power they need. 

The tech giant announced the “strategic partnership” with renewable energy developer Intersect Power and clean energy investor TPG Rise Climate on Dec. 10. The three companies plan to “develop industrial parks with gigawatts of data center capacity in the U.S., co-located with new clean energy plants to power them,” according to Google’s announcement. 

The first phase of the partnership’s first project is expected to go online in 2026 and be fully completed by 2027, said Ruth Porat, president and chief investment officer of Google and its parent company Alphabet. Responding to a NetZero Insider query, a Google spokesperson said no further details on the project are being released at this time.  

To launch the partnership, Google and TPG Rise Climate are lead investors in an $800 million round of funding, and they expect to attract up to $20 billion in infrastructure investments by the end of the decade, according to Intersect Power’s announcement.

“This model is a great opportunity to apply private capital to the tight coupling of load growth with new clean energy in markets across the U.S., and ultimately globally,” Porat says in a blog post on the Google website. “This ‘power first’ approach to data center development is an evolved model that can significantly reduce delivery timelines of new power generation and the projects that will use it — and is designed to ease grid burden and improve overall reliability and affordability for all energy customers.” 

The clean energy projects will be “purpose-built and right-sized” for individual data centers, Porat said. Google will be an anchor off-taker for Intersect’s co-located projects. “Once built, this means the Google data center would come online alongside its own clean power,” Porat said. 

Sheldon Kimber, CEO and founder of Intersect Power, called the partnership “an evolution of the way hyperscalers and power providers have previously worked together. We can and are developing innovative solutions to expand data center capacity while reducing the strain on the grid. Deep, collaborative partnerships combined with creative problem-solving are the only way that we can meet the explosion of AI growth, as well as society’s accelerating electricity demand.” 

Intersect currently has 2.2 GW of solar and 2.4 GWh of storage in operation or under construction, primarily in California and Texas, according to the company website. An additional other 4 GW of solar and 10 GWh of storage are expected to break ground in 2025.  

The company often co-locates its projects with an industrial off-taker, such as a data center,; so, they do not add major demand to regional distribution or transmission lines, according to a company spokesperson. 

“By aligning capital, innovation, and ambition, we expect this partnership to achieve unprecedented scale at our first co-located project, and we have set ourselves on a course to deliver several more large-scale, co-located data centers and clean energy power plants across the U.S.,” said Ed Beckley, a managing partner of TPG Rise Climate. 

Power Demand Doubles

Google’s latest partnership comes as predictions of demand growth connected to AI and data centers continue to spike. Industry consultant Grid Strategies released a new report Dec. 5, with a 15.8% increase in demand forecast for 2029. 

The new figure represents an 11% increase from the organization’s previous five-year prediction, made about a year ago. (See Grid Strategies’ 5-year Demand Growth Forecast Rises.) 

“Power demand had doubled last year from the prior year; lo and behold, it has doubled again,” Rob Gramlich, Grid Strategies president, told reporters during a press briefing. 

The increase in power demand has put pressure on companies like Google that have committed to cutting their greenhouse gas emissions. In its most recent sustainability report, the company said it posted a 13% year-over-year increase in GHG emissions in 2023, driven primarily by its supply chains and the voracious power demands of its artificial intelligence data centers. 

The company’s 2023 emissions totaled the equivalent of 14.3 million tons of carbon dioxide, up a 48% increase over its 2019 base year, and the report says Google expects further increases “before dropping to our absolute emission reduction target” — net zero by 2030. (See Google: AI, Data Centers Drive 13% Rise in GHG Emissions.) 

Some utilities have responded to the increased demand by planning new natural gas facilities. But Google and other hyperscalers, such as Microsoft and Amazon Web Services, are pursuing a range of partnerships and agreements aimed at procuring increasing amounts of clean energy and cutting the environmental impacts of their data centers. 

In a Dec. 9 blog post, Microsoft touted a new data center design that uses no water for cooling its servers, which will save 125 million liters of water per year per data center. The company has pledged that by 2030 its data centers will be carbon-negative and water-positive and produce zero waste. 

In October, Google signed an agreement with Kairos Power, a developer of small modular reactors, to purchase power from multiple SMRs, with the goal of developing a 500– MW fleet by 2035, according to the Kairos announcement. The Kairos SMRs are deployed in pairs totaling 150 MW, or 75 MW each. (See Google, Kairos Sign 500-MW Nuclear PPA.) 

Amazon leads a $500 million investment in X-energy, another SMR developer, with the goal of bringing 5 GW of new clean, dispatchable power online by 2039, according to an X-energy announcement. 

At the same time, co-location of data centers and existing nuclear plants has become a sensitive issue as utilities and grid operators have raised concerns about the impact on grid reliability. Amazon’s purchase of a data center co-located with Talen Energy’s Susquehanna nuclear plant in Pennsylvania sparked objections from American Electric Power and Exelon.  

FERC held a technical conference on co-location Nov. 1 and recently rejected Talen’s proposal to increase the amount of power the data center could take from the nuclear plant from 300 MW to 480 MW. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

Posted on

FERC Approves Fines on Batteries for Misleading Bids in CAISO

FERC has approved a consent and stipulation agreement between its Office of Enforcement and the operators of two battery storage projects in CAISO imposing nearly $3.5 million in fines on the companies for submitting inaccurate initial state of charge values that led to undue bid cost recovery (BCR) payments (IN24-13).

Sonoran West Solar Holdings 1 and 2, owned by RE Crimson, agreed to disgorge the $2,473,265 in BCR payments they received from Oct. 1, 2022, through Feb. 17, 2023, and pay a $1 million civil penalty to the U.S. Treasury. The companies stipulated to the facts of Enforcement’s investigation but neither admitted nor denied any violations.

The Sonoran entities each operate a battery at the Crimson Battery Project in California’s Riverside County. Crimson 1 is a 200-MW/800-MWh battery, and Crimson 2 is 150 MW/600 MWh.

According to the CAISO tariff, if a battery submits a day-ahead bid at 10 a.m., it has the option to forecast its state of charge at the beginning of the next operating day, referred to as the battery’s “initial state of charge.”

Enforcement found that during the relevant period, the Sonoran entities frequently submitted biddable initial state of charge parameters to CAISO that reflected a value that was other than a “forecasted starting physical location,” or the state of charge the batteries were forecasted to hold at the start of the real-time market.

The companies submitted initial state of charge values indicating their batteries would be available to receive discharge awards at midnight and the early morning hours of the following day. On average, Crimson 1 and Crimson 2’s initial state of charge values were 480 MWh and 426 MWh higher, respectively, than their telemetered state of charge at midnight.

Additionally, on Oct. 24 and Nov. 28, 2022, and Jan. 14 and 15, 2023, the companies submitted outage cards with a maximum stored energy of 0 MWh, indicating that the battery needed to be fully discharged in advance of the outage. As a result, they received day-ahead awards to discharge to sell energy prior to the outages.

Because the day-ahead bids were at or near the CAISO bid cap of $1,000, the awards were uneconomic and resulted in BCR payments they would not have obtained if they had submitted accurate information. CAISO’s Department of Market Monitoring flagged the payments and, after department inquiries and Enforcement’s investigation began, the Sonoran entities began implementing processes to minimize future likelihood that initial state of charge and maximum stored energy for outages would be misreported.

Enforcement determined that the initial state of charge values submitted to CAISO during the relevant period were “false and misleading” because they did not reflect a forecasted physical starting location, nor the reasonably expected availability of its batteries at midnight.

The companies also will submit an annual compliance monitoring report to Enforcement for at least one year.

In its Dec. 5 order, FERC found “that the agreement is a fair and equitable resolution of the matters concerned and is in the public interest.” It directed CAISO to allocate the disgorged funds in its discretion for the benefit of ISO customers.

CAISO and stakeholders have been working over the past six months “to evolve existing bid cost recovery rules for energy storage resources to ensure fair and equitable treatment of these resources and reduce unwarranted bid cost recovery payments,” ISO spokesperson Anne Gonzales said.

The ISO is kicking off a new initiative Dec. 11 to continue addressing the issue.

Posted on

SPP Board Approves Need Dates for Last ITP Projects

SPP’s Board of Directors finally approved the winter-weather staging of a pair of transmission projects that have been held up since October by stakeholder concerns over their need dates and whether they would be competitively bid.

During a virtual meeting Dec. 9, the board approved need dates for the two projects by endorsing the Markets and Operations Policy Committee’s votes the week before: a December 2028 date for the 345-kV Tobias-Elm Creek transmission line on the western side of SPP’s footprint and a December 2025 need date for the 345-kV Buffalo Gap-Delaware project from Kansas into Southwest Missouri. 

The latter project’s need date was amended from December 2028 during the MOPC meeting, overriding staff’s recommendation. (See SPP Stakeholders Endorse Need Dates for Delayed Transmission Projects.) 

The board’s approval completes the 2024 Integrated Transmission Planning assessment, a record-breaking $7.65 billion portfolio of 89 projects. The directors delayed a decision on the last two projects’ need dates — the earliest that staff identify a project is needed — after failing to reach consensus during several hours of discussion in their October meeting. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

Evergy and other Missouri and Kansas stakeholders were particularly keen on moving up the 154-mile, $484.1 million Buffalo Gap-Delaware project, which brings a new extra-high-voltage source into Missouri that will support mitigation of Wichita-area congestion, Missouri system voltage and transfers from the SPP footprint into Missouri. The project was identified through a model based on December 2022’s Winter Storm Elliott that also analyzed 2025 and 2028. 

Evergy, with operations in both states, joined with City Utilities of Springfield (Mo.) and Liberty Utilities in filing a letter before the board meeting urging the earlier need date. They said establishing an immediate need-by date is consistent with SPP’s tariff and the ITP manual; the project will address reliability violations found in all the models and decrease the risk of load shed; and it has broad stakeholder support. 

“SPP took a novel approach this year to address resiliency projects by studying select winter weather events because they knew … there was a problem that needed to be addressed that hadn’t been addressed previously, and some of that work resulted in the single most cost-effective ITP in SPP history,” said Kayla Hahn, chair of the Missouri Public Service Commission. “Unfortunately, I’m concerned that that work could potentially be undercut by the delay of this particular project.” 

“We have known for some time that the environment created by our generational challenge will put pressure on many aspects of our processes and culture, whether it be setting a longer-term [planning reserve margin] fully assessing resiliency and winter weather scenarios, or assessing our short-term reliability project list,” board Chair John Cupparo said. “We will be facing unprecedented situations that may run counter to our experience on how to analyze and address these issues. How we respond to those situations may also deviate from historical practice but must still be consistent with our regulatory obligations and our mission.” 

The board’s Members Committee approved the Buffalo Gap-Delaware project with its advisory vote, 16-6, opposed primarily by renewable interests. 

“We’ve heard a lot about how these upgrades are needed for reliability. We’ve been burned by making decisions based on [transmission owners] saying one thing publicly but not moving forward on much-needed transmission,” EDP Renewables’ David Mindham said. “There’s currently no way to hold TOs accountable for not building transmission timely in SPP. If we have the later need date, these projects will be competitive, and that shines a big old spotlight on” the TOs. 

The committee approved the Tobias-Elm Creek Project, 11-7, with four abstentions. TOs were in the opposition, with some saying they still had questions over staff’s use of the winter models. The project is an 85-mile segment valued at $887.5 million. 

JTIQ NTCs Coming Soon

The board endorsed staff’s recommendation to approve the three SPP projects in the Joint Targeted Interconnection Queue (JTIQ) portfolio with MISO and directed the RTO to issue them notifications to construct. 

The three projects — a new 345/161-kV double circuit and rebuilt 161-kV lines near Omaha, Neb.; new 345-kV lines in Nebraska; and an expanded and rebuilt 345-kV substation in Sibley, Iowa — cost a combined $436 million, according to 2023 conceptual engineering and construction estimates. The JTIQ portfolio’s five projects cost a combined $1.6 billion. 

However, SPP and MISO expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to offset some of the projects’ capital costs. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) 

FERC in November approved tariff revisions and modifications to the joint operating agreement between the two grid operators that enshrines a structural and cost-allocation framework for the five 345-kV projects (ER24-2798, ER24-2825). The RTOs plan to allocate 100% of the projects’ costs to interconnection customers, consistent with the cost-causation principle. (See FERC Approves JTIQ Framework, Cost Allocation.) 

The effort began in 2020. The RTOs say the portfolio will enable between 28 GW and 53 GW of interregional generation capacity near their seam. 

The committee unanimously favored the motion, 22-0. 

Lang, Hough to Lead MOPC

By approving its consent agenda, the board sided with the Corporate Governance Committee’s recommendation that Omaha Public Power District’s Joe Lang and City Utilities of Springfield’s Olivia Hough serve as MOPC’s chair and vice chair, respectively. They will serve two-year terms expiring Dec. 31, 2026. 

The agenda’s approval also results in the following organizational group chairs for the next two years:  

    • Credit Practices Working Group: Caleb Head, Northeast Texas Electric Cooperative.
    • Economic Studies Working Group: Calvin Daniels, Western Farmers Electric Cooperative. 
    • Project Cost Working Group: Angie Anderson, Sunflower Electric Power. 
    • System Protection and Control Advisory Group: David Oswald, Liberty Utilities. 
    • Market Working Group: Richard Ross, American Electric Power. 
    • Operations Training Users Forum: Derek Stafford, Grand River Dam Authority. 
    • Generation Interconnection Advisory Group: Jason Tanner, NextEra Energy. 

All the chairs are incumbents except for Oswald and Tanner. Both are their groups’ vice chairs. 

The consent agenda also will revise the PCWG’s scope to include reviewing delayed upgrades and providing recommendations to the board in a timely manner. 

Posted on

NERC Board of Trustees Briefs: Dec. 10, 2024

In its last meeting of the year on Dec. 10, NERC’s Board of Trustees voted to adopt a number of new reliability standards, along with taking action on multiple organizational items, capping off what Chair Kenneth DeFontes called “an extraordinary year” for the ERO Enterprise.

Standards Approved for FERC Submission

Trustees first accepted CIP-003-11 (Cybersecurity — security management controls), produced by Project 2023-04 (Modifications to CIP-003). The new standard addresses the risk of grid-connected distributed cyber systems being targeted by malicious actors for use in a coordinated attack. It requires entities to implement controls on inbound and outbound electronic access, detection of suspicious or malicious communications, user authentication and disabling vendor electronic access.

Next, the board approved TPL-008-1 (Transmission system planning performance requirements for extreme temperature events). NERC developed the standard in response to FERC’s Order 896, which directed the ERO to develop a standard to require entities to plan for extreme heat and cold weather events. (See FERC Approves More Extreme Weather Rules.) The board’s approval means the standard can be submitted in time to meet FERC’s deadline of Dec. 23, 2024.

Trustees then moved to CIP-002-8 (Cybersecurity — BES cyber system categorization), which is intended to improve risk identification by ensuring transmission owner control centers that perform the functions of a transmission operator are identified correctly. Members approved this standard unanimously, as they did with the other proposed standards.

Finally, the board accepted BAL-007-1 (Near-term energy reliability assessments) and TOP-003-7 (Transmission operator and balancing authority data and information specification and collection). The standards will require entities to evaluate energy assurance through energy reliability assessments and develop corrective action plans or take other actions to address identified risks in the appropriate time horizons.

After the standards actions, the board approved NERC’s 2025-2027 Reliability Standards Development Plan (page 40 in the agenda). The RSDP lays out time frames and resources available for projects under development or expected to begin by the end of 2024.

Organizational Items Endorsed

The board next agreed to authorize a data request to assess the cold weather performance of generating units. The request will be issued under Section 1600 of NERC’s Rules of Procedure, initially in 2025 and annually thereafter; relevant entities must submit the required information by May 15 of each year.

Trustees also approved the ERO Enterprise Long-term Strategy, a document outlining key focus areas to guide NERC and the regional entities’ business planning practices starting in 2026, and 2025 Work Plan Priorities. The latter document lists the highest-priority items for 2025 as outlined in its 2023-2025 strategic plan.

Board members then approved a set of proposed compensation changes resulting from a market study performed earlier this year by Meridian Compensation Partners at the direction of NERC’s management. The ERO’s governance guidelines require NERC to perform such a study every three years, along with an annual review of trustee compensation.

As explained by Trustee George Hawkins, Meridian’s study found that NERC’s average trustee pay of $141,000 is “in the bottom half of the competitive pay range” and that “an increase in trustee compensation is warranted.” NERC’s Corporate Governance and Human Resources Committee recommended that compensation be adjusted over the next three years as follows:

    • Annual board retainer: from $135,000 currently to $150,000 in 2025, $160,000 in 2026 and $170,000 in 2027.
    • Committee chair fee: from $10,000 now to $15,000 in all three years.
    • Board chair retainer: from $47,500 to $55,000 in all three years.
    • Vice chair retainer: from $10,000 to $15,000 in all three years.

Board advisory and liaison support fees would remain unchanged at $5,000 per year.

Board to Trial New Meeting Schedule

Chair elect Suzanne Keenan finished the meeting by presenting attendees with an updated schedule for board meetings that will see trustees gather in person more often.

For the past two years, NERC’s board has been holding two in-person meetings per year, in February and August. The May meeting has followed a hybrid format in which trustees and Member Representatives Committee members meet in person while other attendees join remotely, with the MRC and board’s final meetings of the year held entirely online.

Keenan said trustees have received feedback over the past two years indicating “a clear concern” among industry stakeholders about “the length of time without an in-person meeting between August and February.” As a result, the board decided on a new “cadence” of meetings that will debut in 2026.

Under the new schedule, Keenan said, the board will hold three in-person meetings each year, in February, June and October. The February meeting will be held at a hotel in the U.S., while the June meetings will alternate annually between NERC’s D.C. office and a hotel in Canada. For the October meeting, in years when the board meets in Canada, trustees and the MRC will gather at NERC’s D.C. office; in other years they will meet at a U.S. hotel.

Keenan said the board will consider 2026 and 2027 a “trial period” for the new schedule, with a review planned for December of both years to determine if any further adjustments are needed. She expressed hope that the schedule will “deconflict with some of the larger industry conferences” such as the annual CAMPUT conference of Canadian utility regulators held in May.