In a two-day virtual meeting, members of NERC’s Reliability and Security Technical Committee (RSTC) worked through what Chair Rich Hydzik, of Avista, called “a fairly strong agenda” addressing “issues … as intellectually fulfilling as any group I could imagine at NERC.”
Hydzik opened the meeting by welcoming the RSTC’s incoming members, chosen in an election that closed Nov. 20. Scott Klauminzer, Gayle Nansel, Mohammad Awad and Drew Bonser will represent Sector 2 (State/municipal utility), Sector 4 (Federal or provincial utility/power marketing administration), Sector 7 (Electricity marketer) and Sector 10 (ISO/RTO), respectively.
The new members will replace departing members Saul Rojas in Sector 2, Edison Elizeh in Sector 4 and Eric Miller in Sector 10, whose terms will expire Jan. 31, 2025. The seat for Sector 7 is currently vacant, having converted to an at-large seat after not receiving any nominations in the last election.
Current at-large member Srinivas Kappagantula will take the seat of Mark Spencer in Sector 6 (Merchant electricity generator), whose term also is ending. The remaining seats in sectors 1, 3, 5, 9 and 12 will continue to be held by Todd Lucas, Marc Child, Nicola Parrotta, Darryl Lawrence and Christine Ericson, who were all re-elected. Sector 8 (Large end-use electricity customer), which was also converted to at-large, did not receive any nominations and will remain empty until the RSTC holds a special election.
Strategic Plan and Other Actions
Members unanimously approved the RSTC’s 2025-2026 Strategic Plan, which “guides the functions and core mission of the RSTC [with] a sustainable set of expectations and deliverables,” according to the plan’s introduction (on page 22 of the agenda).
A group of six volunteers from the RSTC membership reviewed the plan, according to Vice Chair John Stephens, director of power system control and planning at City Utilities of Springfield. He said the team “didn’t make any major changes” to the plan because the risk items identified by the Reliability Issues Steering Committee in its biennial risk report, on which the strategic plan is based, have not changed since 2023.
However, Stephens said the team did note that the RSTC formed the Large Loads Task Force and the Electric Vehicle Task Force earlier in 2024 to study the reliability impacts of emerging large loads such as data centers and EV chargers, respectively. He said the plan has been updated to include the work of these groups.
The committee then approved several white papers presenting recommended changes to regulatory processes to encourage the adoption of innovative technology in the electric industry and areas of improvement for identifying and addressing the reliability impacts of distributed energy resources. It also approved a technical reference document outlining how to perform energy reliability assessments.
However, another technical reference document suggested by NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) ran into headwinds during the meeting, ultimately failing to gain the votes needed for approval.
The SPIDERWG created the report to “document the type and tenor of industry comments” received on a standard authorization request it created to clarify the role of DERs in operational planning assessments and real-time assessments. SPIDERWG Chair Shayan Rizvi said that after the industry’s comments, the group felt that a new standard was not necessary to address the reliability concerns but that a technical reference document outlining the issues involved could be helpful.
However, several attendees expressed concern over the document’s perceived lack of direction. Ahmed Maria, of Ontario’s Independent Electric System Operator, said that while “well written,” the paper “seemed to present a problem and not the solution.” Ryan Quint of Elevate Energy Consulting agreed, proposing that the document be sent back to the SPIDERWG for more development.
“I think that it could really be useful to spend a bit more time laying out a path forward and making sure that it’s well documented, so that if it ever was picked back up, there is a purpose to it,” Quint said. “I just caution throwing this up there as a bunch of problems without solutions.”
After more discussion, Hydzik asked Wayne Guttormson of SaskPower — who had moved to approve the document — if he was willing to withdraw his motion, to which Guttormson assented. Rizvi asked that Hydzik approve a 30-day comment period for the document so that members of the RSTC could share their thoughts in more detail, to which Hydzik agreed.
WASHINGTON ― President-elect Donald Trump’s November victory has not slowed the number of new loan applications coming into the Department of Energy’s Loan Programs Office, according to LPO Director Jigar Shah.
The LPO has 212 active applications seeking $324.3 billion in federal dollars, Shah said during his Dec. 12 appearance at the U.S. Energy Association’s Advanced Energy Technology Showcase at the Ronald Reagan Building. The office continues to receive “an average of one application a week,” he said. “The latest monthly application activity report went up by $20 billion this last month. And so, it’s also been a surprise to me, but there’s been a lot of new applications that continue to come in.”
What’s driving the ongoing activity is artificial intelligence and load growth and the need to maintain U.S. leadership in energy innovation and rebuilding domestic supply chains, he said.
“We need to allow all these manufacturing facilities and onshoring and reshoring facilities to interconnect to the grid. [This] remains a priority, right?” Shah said. “AI, load growth remains a priority. We want to win AI, right? The technologies that we’re covering, everything from nuclear power to enhanced geothermal to next-generation grid technology to virtual power plants are all essential to meeting this moment. All of it, right?”
Shah’s four years at LPO have been dedicated to making the office a “bridge to bankability” for clean tech entrepreneurs, which in many cases has meant mentoring early stage companies to the point where they can apply for a loan, he said.
Trump’s pronouncements on energy policy since the election have focused on U.S. energy dominance and independence, goals Shah argues will make energy innovation and entrepreneurship critical.
According to its most recent report, the office still has close to $400 billion in unspent loan authority, and Shah said the LPO provides essential financing to “the most exciting entrepreneurs and innovators that America has to offer. I think they’re irresistible. I think folks are going to want us to continue to do big things.”
Pointing to technologies that have bipartisan support, he said, “if you’re going to scale up nuclear power, if you’re going to scale up clean hydrogen, if you’re going to scale up these technologies, there’s no other place to get affordable debt to do these first-time projects outside the Loan Programs Office.”
Shah said Trump has yet to name a transition team for DOE, so he has not been able to talk with anyone from the incoming staff of Chris Wright, the CEO of Liberty Energy, a natural gas company, whom Trump has nominated to head the department. But Shah said his first step will be to introduce the transition team to the team of investment professionals and energy experts he has assembled at LPO.
“We’ve built a world-class team, and this world-class team wants to put this money out the door to help American entrepreneurs and innovators to meet the moment,” he said.
DOE and the LPO still face a range of unknowns, such as whether they might fall victim to the staff-cutting agenda of Elon Musk and Vivek Ramaswamy’s Department of Government Efficiency.
Shah again remains confident. “When you look at the Loan Programs Office today, for the amount of debt that we’re putting out the door, the private sector would have three times the number of employees that we would have,” he said. “So, I think we’re probably a hallmark of government efficiency in terms of the way in which we’ve processed the loans, the way in which we’ve substantially reduced the time that it takes to get a loan.”
Another strong selling point is “how much private-sector capital we’ve crowded in,” Shah said. “When you get a conditional payment from the loan programs office, every single one of our applicants has been able to successfully raise equity, which is not easy these days, right? … I think that the Loan Programs Office is government doing its job well.”
Shah also said companies that have either received a conditional loan or finalized a contract should be safe from any clawback efforts. Conditional commitments are binding contracts, he said.
“I think all of these projects are important to the communities that they’re in; they’re important to the states that they’re in; they’re important to the congressional districts they’re in,” Shah said.
“I don’t know how many entrepreneurs and innovators you’ve met, but they are ferocious,” he said. “They will walk through walls to accomplish their goals. If they cannot build them here, they will go to another country to build them. I don’t know why anyone would want these entrepreneurs and innovators to leave our country and go to another country to commercialize American technology, because we make a mistake. All the R&D, all the invention was done here. Why would people not want them to scale them here?”
Requests that two developers submitted this year have prompted the U.S. Bureau of Ocean Energy Management to start planning a 2026 offshore wind auction in the Gulf of Mexico.
The new development is a change from recent history: The first Gulf of Mexico wind lease auction, in August 2023, attracted only two bidders, lasted only two rounds and resulted in a winning bid of just $5.6 million for only one of the three areas offered.
But Hecate Energy Gulf Wind submitted an unsolicited request to lease two areas that had not been on the auction block, named Option C and Option D, totaling 142,000 acres southwest of Houston. BOEM then published a request for competitive interest to see if any other developers might want to lease C and D. Invenergy GOM Offshore Wind responded.
BOEM determined that both companies were legally, technically and financially qualified to hold a renewable energy lease in the Gulf of Mexico, setting the process in motion.
President Joe Biden, a staunch offshore wind supporter, was running for reelection at the time and potentially could have seen all of the auctions carried out in his second term. Instead, all eight auctions remaining on the timeline would fall during the second term of President-elect Donald Trump, a staunch offshore wind critic.
Along with the politics that impact U.S. offshore wind power development, the Gulf of Mexico itself poses some significant challenges to power generation. The wind there is typically weaker than in the West and East coasts targeted for wind power development — except during the gulf’s frequent hurricanes. New equipment must be designed to maximize energy output in light wind and minimize physical damage in heavy wind.
Also, electricity is relatively cheap in the region, increasing the competitive disadvantage of offshore wind, and state leaders have not been clamoring for offshore wind the way Northeast and California officials have.
Still, BOEM pushes on in the gulf. Its regional director, Jim Kendall, said in a news release Dec. 12, “The Gulf of Mexico remains an attractive option for offshore wind energy development. We are excited about the future of this emerging sector in the region.”
One selling point for offshore wind in the gulf has been its potential as a source of power to generate green hydrogen, which is projected to grow as an industry in the region.
Hecate touched on this in its proposal for up to 133 turbines totaling up to 3 GW of capacity. It listed a range of potential uses beyond straightforward interconnection to the grid, including power purchase agreements with private off-takers and direct production of other energy resources.
The Southern Shrimp Alliance called on BOEM to reject the request for Option C and adjust Option D because of expected conflicts with shrimping.
The Nature Conservancy endorsed renewable energy development but listed a set of environmental protections that must accompany it and noted that wind-to-hydrogen production would require further analysis under the National Environmental Policy Act.
The Texas General Land Office noted that Hecate has no experience with offshore wind development and said there are multiple, significant concerns that must be addressed before it would allow a wind power lessee to run a transmission line across submerged state lands.
To meet the electricity demand expected from new data centers in the Northwest, stakeholders must collaborate to efficiently invest capital and explore controversial solutions like establishing a regional transmission organization, panelists said in a webinar hosted by the Northwest Power and Conservation Council on Dec. 11.
The companies building data centers have “extraordinarily” deep pockets, which means there are a lot of opportunities to fund large infrastructure projects on the backs of individual customers, according to Brian Janous, co-founder and chief commercial officer at Cloverleaf Infrastructure.
Companies already have showcased their willingness to fund energy infrastructure, Janous said.
Some recent examples include GE Vernova and ExxonMobil announcing new natural gas projects to meet data center demand. On Dec. 10, Google partnered with renewable energy developer Intersect Power and clean energy investor TPG Rise Climate to power the search giant’s data centers.
“The problem that we have is not that there’s not capital,” said Janous. “The problem we have is there’s not that many opportunities right now to invest that capital efficiently.”
Planners need to change their mentality around flexibility and speed to boost investments in power systems and other benefits data centers can bring to a region, Janous said.
Robert Cromwell, consultant and former vice president of power supply at the Umatilla Electric Cooperative, agreed.
“There is an enormous opportunity for the balancing authority areas or the transmission service providers to integrate operations with the data center campuses when they’re built,” Cromwell said.
But council member Douglas Grob questioned whether it’s possible to integrate data center customers at the speed they ask for, saying states are slowed by their own rules and court systems.
Cromwell said the answer “would be a regional transmission organization or an independent system operator where all the different balancing authorities in the West merge and you have a single entity that’s dispatching load and generation collectively.”
Cromwell said there’s growing recognition RTOs are a more efficient approach, “but it runs directly contrary to some of the core values within public power.”
“It’s something that just rubs a lot of people the wrong way, and you’ve just got to be honest about that,” Cromwell said. “But candidly, I’ve been working on these issues for a good chunk of my career, and I don’t see another path that will solve our problem.”
Sarah Smith, a research scientist with the federally funded Lawrence Berkeley National Laboratory, said there’s an opportunity to be creative, but it “will take some new ideas and new models.”
Smith noted the federal government is focused on speeding up new transmission by improving the permitting process and the interconnection queue, “both on the generation side and the load side.”
However, there are other avenues for regions to successfully attract data centers, which can be advantageous for local governments, Smith said. For example, data centers can repurpose old mining sites that already have power infrastructure in place, and “you wouldn’t have to reenter that interconnection queue,” Smith added.
Finding sites “where it’s more feasible to add that load in the short term” can provide regions a chance to offer those sites to data centers so that the “industry isn’t making requests that are really hard to meet when there might be other sites and options on the table,” Smith said.
The Northwest Power and Conservation Council hosted the webinar shortly after the WECC published a report that forecasts “staggering” growth in electricity demand in the Western Interconnection over the next decade.
The report predicts annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and double the 9.6% growth forecast in 2022 resource plans.
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 MISO 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 MISO at a Dec. 12 Board of Directors 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 Dec. 10 Markets Committee of the MISO Board of Directors, 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 another 4-7 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, MISO 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 MISO 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.
MISO IMM 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 Presidents Day, 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 MISO’s 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%.
