Voltus filed a complaint with FERC against MISO on Dec. 11 asking it to require the RTO to allow the replacement of customers who sign up as load-modifying resources (LMRs) in the Planning Reserve Auctions (EL25-37).
Aggregators like Voltus can sign up customers to provide demand response and clear that capability in the capacity market, but then those customers could go out of business or otherwise be unable to supply the capacity when needed, the company told the commission. When that happens, aggregators need to be able to replace the resource with another customer facility to provide the contracted DR.
“Generators that become unavailable can be replaced, and there is no reason to treat LMRs differently,” Voltus said.
Voltus argued that MISO’s tariff as written does not treat LMRs differently, and it expressly permits such replacements. MISO used to interpret it that way until a tariff change in 2022.
“An apparently unintended consequence of that change is that MISO believes the tariff no longer authorizes MISO to permit an aggregator to replace an LMR that cleared the capacity market but is no longer available, even though a similarly situated generator may be replaced,” Voltus said. “A generator may even use a demand response resource as a replacement resource, but in the circumstance where a demand response resource becomes unavailable, MISO does not allow for its replacement.”
The 2022 change requires that generators be replaced after a prolonged outage, but Voltus said its “plain language” does not implicate replacing customers supplying DR.
“There is not any discussion of such disparate treatment sufficient to provide notice to market participants,” Voltus said. “In short, if the 2022 tariff amendment had the effect attributed by MISO, it appears to have been inadvertent. Because the plain language of the amendment leaves plenty of room for an interpretation that no such change occurred, the commission should confirm that no such change did occur.”
If FERC finds MISO’s interpretation to be correct, then the commission should order a change in wording to reinstate LMRs’ ability to be replaced because the current practice wrongfully omits useful resources from the reliability equation, the company argued.
“MISO deems LMRs useful enough to replace generation,” Voltus said. “There can be no good reason why such a useful resource should not be afforded the right to be replaced itself.”
PRAs are run in April for delivery years that start June 1, and LMRs can bid into the auctions as zonal resource credits (ZRCs).
The new rule was meant to require that generators that are offline for more than 31 days be replaced, which MISO felt was necessary as the PRA shifted to a seasonal construct. After the amendment went into effect, MISO cited a sentence from it as the basis for its interpretation that LMRs could not be replaced: “A planning resource may not transfer its performance requirements by replacing the cleared ZRCs with uncleared ZRCs other than in the case of suspension, retirement, catastrophic generator outage, or full or partial generator planned outages that may exceed 31 days in the season.”
While the reasoning for replacing resources is focused on generators, Voltus said the “plain meaning” of the terms “retirement” and “suspension” should be applied to the customer sites backing LMRs. DR is one of the last resources MISO operators use to prevent load shedding, so the more of it available means they can better respond to emergency conditions, it argued.
WASHINGTON ― Northern Virginia isn’t the only place scrambling to find enough electricity to keep its data centers powered 24/7, said Javier Fernandez, president and CEO of Omaha Public Power District.
Omaha is a central hub in Nebraska and Iowa’s “Silicon Prairie,” which is attracting new hyperscale projects with the region’s low-priced, reliable electricity, open land and digital fiber backbone network. A recent S&P Global analysis placed the city second, behind Northern Virginia, in the amount of power it was dedicating to data centers in 2023. Meta has one of the largest enterprise data center campuses in the country in the region, and Google has invested $4.4 billion in three data centers in the state, two in operation in OPPD’s service territory and a third under construction in Lincoln.
In the past year, the utility has received 19 requests for power from developers considering locating data centers in the region. To meet the growth, Fernandez said OPPD will have to almost double its generation capacity in the next five years, adding an additional 3.2 GW to the 3.6 GW it has online.
“It is time for the industry as a whole to step up and continue to build what this country deserves,” he said. “This is one place where we really cannot afford to fail. We cannot afford to delay infrastructure.”
Fernandez, also vice chair of the Large Public Power Council, was in D.C. on Dec. 11 for a meeting of LPPC members to discuss their policy priorities for the administration of President-elect Donald Trump and the Republican-led Congress.
In an exclusive interview with NetZero Insider, he and Tom Falcone, who will become president of LPPC on Jan. 1, 2025, made a case for the public power business model as one that possibly is better suited to meet the imperatives of demand growth than regulated, investor-owned utilities.
“We’re not for profit,” Falcone said. “We’re just here to serve our customers. We’re community governed, so we meet the priorities of our local communities,” which now include massive load growth for economic development, he said.
Utilities like OPPD also have closer ties to their communities, which can make permitting new generation or transmission projects easier, Fernandez said. Working through local permitting and zoning rules still can be difficult, he said, “but it helps tremendously when you have the community saying, ‘Oh, it’s my local utility who’s building. I’m willing to play ball with them more than someone we don’t know from out of state.’”
Fernandez also noted that hyperscalers like Google don’t come in only with new load, “they’re coming in with solutions. How do we make this work better for the community? How do we make this work and help the utility serve us and serve the community?”
One example: Google and OPPD negotiated a contract allowing the utility to use power from a wind farm Google owns in Kansas, Fernandez said.
Finally, public power, both LPPC members and the country’s more than 2,000 municipal utilities typically do not face the same hurdles in obtaining approvals from state regulators to launch new programs or pilots. OPPD has put 1 GW of new power online in 2024, Fernandez said.
“We’re not just talking and wringing hands,” he said. “We’re actually doing, delivering, putting steel in the ground, panels on the ground.”
Both Fernandez and Falcone recognize the challenges ahead will be considerable and complicated. Over the next five years, LPPC’s 29 members ― all large public power utilities in 22 states, serving more than 30 million customers ― must add 9 GW of power capacity at a cost of almost $70 billion.
If It Ain’t Broke
Falcone commutes between his home in New York, where he previously was CEO of the Long Island Power Authority, and D.C., where he talks with lawmakers about specific policies LPPC’s members would and would not like to see.
No. 1 on the no-change list is tax-exempt financing, which, Falcone said, will be critical for public power utilities to build out the generation and transmission they’ll need to meet demand growth.
GOP lawmakers will be beating the bushes for dollars to pay for extending Trump’s 2017 tax cuts, Falcone said. “Whenever you have big tax bills, and this was certainly the case in 2017, you need revenue raisers, and when you have revenue raisers, then people look at everything.”
But, he said, public power utilities “have good access to the tax-exempt bond market. It’s a liquid market. It finances our costs and helps us keep these investments affordable. We’re just looking for things to stay as they are.”
Similarly, LPPC members want to maintain the direct pay provisions of the Inflation Reduction Act, which allow nonprofits that do not pay taxes to monetize the law’s clean energy tax credits.
Prior to passage of the IRA, public power utilities had to work with third-party developers to take advantage of the tax credits, which often required complex transactions in which the third party took part of the tax credit, Falcone said.
“We just want to be on a level playing field with our tax-paying counterparts,” he said. “We own nuclear; we own batteries; we do offshore wind; we do solar. We do all these things that are subsidized, and so we just want to have the same access [so] our customers are not disadvantaged.”
Another thing that doesn’t need fixing is the regional planning policies for public power utilities that are not within an RTO or ISO service territory, which could be changed under the Energy Permitting Reform Act of 2024, introduced by Sens. Joe Manchin (I-W.Va.) and John Barrasso (R-Wyo.).
Falcone says that, as currently written, EPRA would give FERC jurisdiction over regional planning for non-RTO/ISO public power utilities, which neither the utilities nor FERC want.
Public power utilities that are not in the organized markets overseen by FERC traditionally have had the choice of opting out of regional or interregional planning and building their own generation and transmission, he said. “There’s nothing [broken] with that construct,” he said. “It works fine. I’ve been asking everybody, ‘Why are we changing this?’”
EPRA was passed in August by the Senate Energy and Natural Resources Committee, where Manchin is chair and Barrasso ranking member. But the bill is languishing in the final days of the lame duck Congress. While it may be unlikely to pass, permitting reform remains a high priority for Republicans. Barrasso will be GOP Senate Whip when the new Congress convenes in January, so parts of EPRA could be incorporated into new legislation.
‘We’re in a Different World’
Falcone and Fernandez also agree with the conventional wisdom that IRA tax credits that largely have benefited Republican states and districts will have sufficient bipartisan support to survive rollback efforts.
OPPD sees new bioenergy projects in its region, for example, production of ethanol and sustainable aviation fuels, Fernandez said. “A lot of these tax credits are spurring more investment in new technologies that ultimately result in load for us. … If those are taken away, we could see a missed opportunity on the electrification of the economy that’s already starting to happen.”
But, like other utility trade groups, LPPC does want changes to EPA’s final rule on carbon emissions from existing and new power plants powered by fossil fuels. Released in April, the rules require existing coal-fired plants to use carbon capture and sequestration to reduce their emissions 90% by 2032 or close by 2039.
Falcone argues that LPPC members include “some of the greenest utilities in the country,” and their concerns with EPA’s emissions rules are not “about carbon policy or anything else. It’s simply a statement of supply.
“There’s not a robust supply chain, knowledge [or] engineering to get these things done. So, it goes to reliability. … When you’re looking at the problem of demand for electricity outstripping supply, to take further supply offline is a real challenge.”
The rule is being challenged in court, but utilities still will have to comply with it in the interim, he said.
Falcone cited the still-emerging supply chains for new clean, firm technologies — including small modular nuclear reactors, green hydrogen and long-duration storage — as the reason new natural gas-fired plants may be needed to meet growing demand now.
“We would love to see further development of carbon capture, of SMRs, of all these things, but SMRs aren’t permitted or licensed today. Carbon capture isn’t available at scale today. There are no long-duration storage solutions today, other than perhaps pumped hydro,” he said. “So, at some point, you just have to go with what you’ve got.”
And even new natural gas plants may not be an immediate solution due to the challenges of permitting and building new plants and natural gas pipelines, he said.
“We’re in a different world, and the world is one of growth,” Falcone said. “We face constraints in meeting that growth. … What we’re here to do in D.C. … is to help educate policymakers about what the tradeoffs are so they can make the decisions that we will implement, and we’ll be happy to do, but just know what the tradeoffs are.”
The U.S. solar industry is embracing priorities of the incoming Trump administration as it seeks to preserve the momentum it built during the Biden administration.
The Solar Energy Industries Association on Dec. 12 presented a comprehensive policy agenda for Trump and his fellow Republicans who soon will control both houses of Congress.
At no point does SEIA’s new top 10 list of priorities mention solar’s environmental benefits, climate protection or reduced reliance on fossil fuels, all of which are nonstarters with many Republicans.
Instead, it frames the continued growth of solar generation in bullet points more in line with stated GOP priorities:
Achieve American energy dominance.
Eliminate dependence on China.
Surge American manufacturing.
Meet the demands of data centers.
Cut red tape.
Deliver regulatory reform.
Lower taxes.
Support energy choice and energy freedom.
Create jobs for America’s heartland.
Protect private property.
Lest the implication of “heartland” be overlooked, the smaller print points out that six of the top seven solar states are Texas, Florida, North Carolina, Arizona, Nevada and Georgia — all of which Trump carried in the 2024 election.
There is no mention of deep-blue California, the No. 1 solar state. Also omitted are New York, Virginia and Massachusetts, which round out the top 10 and which were carried by Kamala Harris.
SEIA President Abigail Ross Hopper emphasized energy and economics in a news release: “This is a road map for the Trump administration and Congress to capitalize on strong federal solar and storage policies and achieve their vision of a dominant American energy sector. Enacting this agenda will give the United States control of the solar supply chain and ensure American communities benefit from solar and storage jobs and economic growth.”
What impact Donald Trump will have on the renewable energy transition in his second term as U.S. president is the subject of much speculation and trepidation within the renewables industry. He has called climate change a hoax and the IRA a scam. He has spoken repeatedly and strongly about halting offshore wind and has criticized solar at times.
Should Trump want to limit development of renewables, he could make policy changes targeting one sector or another or he could end some of the tax credits, loan guarantees and other financial support the industry receives from the federal government.
But as many organizations hasten to point out, the economic benefits of hundreds of billions of federal dollars that Democrats allocated for renewables have been flowing disproportionately to Republican-majority states.
And Trump has an unpredictable leadership style with changing talking points. So, his actions in office could be more nuanced than some of his rhetoric on the campaign trail.
SEIA also notes the U.S. solar industry grew 128% during Trump’s first term to reach 100 GW of installed capacity in 2020.
But the rate of growth increased sharply under Biden — even amid inflation, supply chain constraints and resulting price volatility — reaching 219.8 GW of installed capacity in the third quarter of 2024.
SEIA’s latest forecast shows 40.5 GW of total installations for all of 2024. Through the third quarter, it said, solar accounted for 64% of all new capacity added to the grid.
The association tallies nearly 280,000 solar jobs at more than 10,000 companies in all 50 states and values the market at $63.6 billion as of 2023.
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.
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.
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.)
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 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.
“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.
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.
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.
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).
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 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.
“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.”
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.
