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December 24, 2024

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Exiting MISO President Proud of Tx Trailblazing, Says Load Growth Doable

Reflecting on his more than two decades at MISO, President Clair Moeller doesn’t hesitate to say that helping to normalize transmission investment is the most pivotal contribution of his career.

Moeller said MISO was able to convey to members that planning should “maximize value for consumers rather than minimizing investments.” In a press call to reflect on his tenure and the state of the industry as he exits, Moeller said around the mid-2000s and early 2010s, MISO began doing an enviable job of showing the value of potential transmission through analyzing production costs and other benefits. That work culminated in MISO’s approximately $6.6 billion Multi-Value Portfolio in 2011, its first comprehensive long-range transmission planning.

Moeller leaves MISO at the end of 2024, as the RTO’s Board of Directors approved a $21.8 billion long-range transmission plan (LRTP) portfolio, a sign of how far MISO has come on transmission planning in the Midwest. (See Longtime MISO President and COO Moeller to Retire.) MISO has vowed to plan more portfolios.

“It’s value engineering rather than cost engineering,” Moeller said. “That’s why we at MISO are accomplishing these transmission investments where other regions are struggling.”

The best advertisement for long-range transmission is to “get steel in the ground,” he said. After that, Moeller said the transmission can speak for itself on its value.

“You can see that as people gain confidence in the answer, it’s easier to repeat,” he said.

Moeller acknowledged long-range transmission takes time, pointing to Cardinal-Hickory Creek’s completion date 13 years after it was approved in 2011. He also said the regulatory process and supply chain are “sequential,” lengthening timelines. He said it’s natural that developers “wait for permission before they order things.”

Moeller said MISO’s LRTP efforts are a combination of members pushing MISO to do more intensive planning and the RTO pulling states along. He said the LRTP represents MISO and members walking “away from the cartoon that says minimizing investment is the way to keep people’s bills down.”

More investment appears certain as load growth climbs around the nation, spurred by the rise of data centers.

“The speed to market for the AI stuff, I think, surprised everybody,” Moeller said.

Moeller said he’s confident that 10 years down the road, enough generation will exist to serve load, but he predicted “turbulence in the short run.”

“By 10 years, we’ll probably be OK,” he said.

Moeller said by that time, MISO’s control room should have new uncertainty tools fashioned out of necessity because of the volatility of renewable energy. He said improved weather forecasting and maintaining adequate reserves to cover severe down-ramping will be essential. MISO will have to “tune” its reserves on hand to the risk of the day, where a several-gigawatt, sudden down-ramp in wind might be commonplace, he said.

“The level of sophistication has to improve by an order of magnitude,” he said, adding that MISO will have to shed the “deterministic model embedded in the industry’s history.”

Moeller said reworking how to measure resource adequacy isn’t new, as MISO has been trying to better quantify risk for a decade.

“These aren’t new problems. The data centers are a new wrinkle,” he said. But he conceded that 20 years ago, “the math was easy” because all generation looked the same and the summer peak was the lone worry.

“I’m quite confident we’ll get through it,” Moeller said, asking that the industry allow engineers the space to work and figure things out.

Moeller said the challenge today between exploding load growth and bringing new generation and transmission online is one of timing, with load moving at a faster pace. He said although data center load always has been on the grid, the 80-MW centers of yesteryear are being supplanted by minimum 800-MW facilities.

He said one prospective data center in MISO would add 2,500 MW of load, rivaling Indianapolis’ demand.

“You don’t build enough resources to serve Indianapolis in 24 months,” he said. “If you order a combustion turbine today, it’s 60 months out. … Those kinds of collisions are going to complicate our lives for the next … five to eight years.”

Moeller said complicating matters, data center developers might negotiate simultaneously with three separate utilities, making load growth appear more prevalent than in reality.

“Everybody signs non-disclosure agreements so they can’t say anything, but then there’s an announcement,” Moeller said, advocating for the industries to calm down the “chaos.”

He said MISO must determine the “blips” from the “trends” to see what types of growth are enduring. Moeller said consultants tell MISO that industrial reshoring might be a passing trend while the appetite for data crunching is more durable and long-lasting.

Within 20 years, Moeller predicted the grid will need dispatchable assets to cover shortfalls that can persist for days during still, overcast days. He said it’s possible the threat of those tricky days will tack on a few years to achieving clean energy goals, but the emergence of data centers today might be able to help fund combustion turbines that can be relied on as a backup source of emergency power.

“It’s that kind of schedule flexibility that can help us get through this,” Moeller said.

Yet, Moeller said data center developers are sending mixed messages where they pay lip service to clean energy goals but turn to combustion turbines today to snap up a 24/7 source of electricity.

Moeller said that double-speak is likely to spell only a temporary hiccup for the industry.

He also implied a second Donald Trump administration ultimately might do little to reverse the clean energy movement.

“I think people understand the change has to happen. … The trends are pretty clear on the greening of the fleet,” Moeller said. “How fast we’re moving changes with administrations, but it doesn’t mean we’re not going to move.”

MISO CEO John Bear praised Moeller for his two decades at the RTO at a Dec. 12 board meeting. He said Moeller accomplished the “unbelievable” feat of getting people to rethink transmission planning to be a value-based endeavor.

“The magic of MISO is that I’ve never had to live outside my values to work here,” were Moeller’s parting words at the board meeting.

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MISO Tells Board RA Fast Lane in Interconnection Queue is a Must

THE WOODLANDS, Texas — MISO told its Board of Directors it’s essential to draft an interconnection queue express lane for generators that resolves resource adequacy risks and has stamps of approval from regulators.  

At a Dec. 10 System Planning Committee, MISO’s Scott Wright told directors that though MISO runs a “good” queue process, it’s “not enough to get us where we’re going.” He said MISO needs to debut a priority study lane for critical generation projects. (See MISO Outlines Plan on Fast-track Queue for Resource Adequacy.) 

Because of capacity sufficiency needs, Wright said MISO can’t afford to wait for the three to four years projects spend in the normal queue, with construction times added to that.   

“This is to fill a gap that’s very real to address until we can get the queue down to a one-year process. This is temporary. This is not an ongoing way of doing business,” he said.  

MISO’s queue clocks in at 312 GW across more than 1,700 projects.  

“What we have is a massive volume deluge, and it’s resulted in large backlogs,” Wright said. “But we need resources now.” 

To meet its upcoming resource adequacy needs, MISO estimates members need to bring at least 17 GW of nameplate capacity online annually, or about 7 GW to 8 GW of accredited capacity. According to MISO records, the footprint brought about 3.4 GW in accredited capacity online in 2024.  

Clean energy groups argue that a dedicated express lane could create equity concerns for projects in the regular queue. They’ve said one-off, accelerated studies for individual projects could result in the RA projects paying far less in network upgrades than their counterpart projects in the regular queue, where major network upgrade costs are spread across groups of projects in study clusters. 

The Sustainable FERC Project has asked MISO to consider making the expedited process a one-time occurrence with a single round of project applications to address states’ near-term resource adequacy risks.  

Clean Grid Alliance’s David Sapper said MISO should rethink filing for the RA fast lane in a “few hurried months.” He told MISO board members at their Dec. 12 meeting that the new process would amount to an “assault on fundamental transmission open-access policies.” 

Sapper said MISO’s specialized study process would create “undue competitive advantage for projects that are allowed to skip the queue and use up existing transmission capabilities while queued projects are held back, thereby degrading their economics.”  

“As a table mate at dinner last night noted — to nobody’s surprise — once investors know there is a way to skip the queue, they won’t want that to go away,” he said.  

MISO staff say if some of the unfinished, delayed resources with signed generator interconnection would come online, MISO would worry less about creating an exclusive avenue in its queue.  

The RTO has amassed 57 GW (or approximately 27 GW in accredited capacity) in planned resources that have made it through the queue, have signed interconnection agreements but remain half-finished due to supply chain hurdles or other holdups.  

Wright also said the sheer volume of projects is “eating away at the effectiveness” of the queue process enough that MISO needs to apply its proposed annual megawatt queue cap on the regular queue. That cap plan is pending before FERC.  

“What we’re doing today isn’t working for tomorrow,” MISO’s Aubrey Johnson said at a Dec. 6 special workshop to discuss the expedited process. 

While the grid operator discusses its RA needs, it’s decided to skip a 2024 cycle of its interconnection queue while it attempts to automate and speed up studies. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.)

MISO also appears to be getting at least some of its wish for postponements of generation retirements, which leadership has suggested as a temporary means of maintaining resource adequacy.  

Alliant Energy announced earlier in December that its coal-fired Columbia Energy Center will operate through 2029 while it and co-owners Madison Gas and Electric and Wisconsin Public Service explore converting one of the units to natural gas to bolster reliability. The coal plant was set to close at the end of 2024, which later was pushed back to 2026.  

Missouri utilities say they plan to build new capacity after last year’s Zone 5 shortfall in the capacity auction, where utilities were exposed to cost of new entry capacity prices at $719.81/MW-day for fall 2024 and spring 2025. Some indicated they would take advantage of MISO’s proposed, fast-track queue process for necessary generation projects.  

Others in the MISO footprint protest the natural gas plant plans that are cropping up as the cure for apprehension over resource adequacy.  

Earlier in December, the Sierra Club and Clean Wisconsin petitioned the Wisconsin Supreme Court to hear their case challenging Wisconsin regulators’ approval of certificate of public necessity for the 625-MW Nemadji Trail Energy Center (NTEC). They argue that the Wisconsin Public Service Commission didn’t adequately weigh the environmental impacts of the plant when they approved it. (See City Council Vote Stalls Planned Wisconsin Gas-fired Plant.)  

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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.)

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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.

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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.

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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.” 

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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.

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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. 

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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.) 

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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.