CAISO’s Department of Market Monitoring on Dec. 12 reported that the ISO saw “one of the highest demand peaks” in recent years, at 48,353 MW on Sept. 5 — but still well short of the record of 52,061 MW in 2022.
Speaking at the ISO’s Market Performance and Planning Forum, Guillermo Bautista Alderete, the department’s director of market analysis and forecasting, highlighted that the peak was also higher than the California Energy Commission’s forecast of 47,160 MW.
Annual CAISO demand typically peaks in July to mid-September. Besides the 2022 record, this year’s figure marked the highest peak load since Sept. 1, 2017, when demand rose to 50,116 MW. It was also an increase of about 8.6% over last year’s 44,534 MW on Aug. 16.
Monthly resource adequacy showings, which came out to be a little over 53,000 MW, slightly increased from 2023 and were sufficient to cover CAISO’s load plus operating reserves in September. That was “the reason why we didn’t have any tight supply conditions to the extent that we have observed in previous years,” Alderete said.
He also noted that there was a significant decrease in gas-fired generation coupled with a significant increase in storage resources: 3.6 GW compared to 5.5 GW.
“That aligns with the present trend that we have seen of quick penetration of storage resources exceeding the 10,000-[MW] mark sometime in 2024,” Alderete said.
Despite what Alderete described as a relatively moderate September, the ISO did support a “reasonable level” of wheel-through transactions, peaking at just over 500 MW.
September also saw the highest participation in the Assistance Energy Transfer (AET) program since its inception in 2023. Nine balancing authority areas opted into the program, accumulating approximately $720,000 in AET surcharges in August and September.
California regulators have approved a $95.2 million funding plan for zero-emission vehicle charging infrastructure, with nearly equal amounts going to charging for passenger vehicles and medium- and heavy-duty trucks.
The California Energy Commission on Dec. 11 approved the funding for the Clean Transportation Program for fiscal 2024/25. The package includes $40 million for light-duty EV charging infrastructure; $38.2 million for medium- and heavy-duty ZEV infrastructure; $15 million in hydrogen-specific funding; and $2 million for workforce development.
The slightly higher funding amount for light-duty charging infrastructure comes after the program has given more money to medium- and heavy-duty ZEV infrastructure over the years, Commissioner Patty Monahan noted.
“But this year, given the fact that we really want to make progress on reaching our state goals for charger deployment, we’re leaning in a little bit more on light duty, but with a very strong focus on equity,” Monahan said.
California will require all new cars sold in the state to be zero emission by 2035. A CEC report finalized this year projects the state will need 1 million public or shared-private light-duty EV chargers by 2030, growing to 2.1 million chargers by 2035.
The state now has about 152,000 public or shared-private EV chargers, a number expected to grow to about 359,000 when chargers are built with previously allocated funding.
Charger Types Debated
CEC staff described the funding plan as a high-level view. Specific projects will be selected later through competitive grant solicitations, block grants and in some cases, direct awards or loans. Among the yet-to-be-determined details is how much funding should go to particular types of light-duty EV chargers.
Bill Magavern with the Coalition for Clean Air made a case for funding Level 1 chargers, which he said could benefit low- and moderate-income drivers living in apartments. “We continue to think that there’s a role for Level 1 charging in providing a really low-cost alternative for some of those multi-family dwellings,” Magavern said.
On the other hand, Commission Chair David Hochschild noted the importance of DC fast chargers to those who drive for a living. He said one in five Uber rides in California now is in an electric vehicle, compared to one in 10 rides nationally. “Time is money. If they’re stuck at a slow charger, it really impedes their ability to drive electric,” Hochschild said. “Access to fast charging is essential to that sector.”
Future Funding
Funding for the CEC’s Clean Transportation Program comes from a surcharge on California vehicle registrations. The program also can receive money from the state’s general fund or the Greenhouse Gas Reduction Fund.
But due to a budget shortfall, those sources did not provide funding to the Clean Transportation Program for fiscal 2024/25. The CEC expects that funding to resume over the next three fiscal years to the tune of $1.3 billion.
Adding the anticipated state funding to this year’s base funding, the CEC investment plan envisions allocating $1.39 billion through fiscal 2027/28. That would include $659 million for light-duty EV charging infrastructure, $668 million for medium- and heavy-duty ZEV infrastructure, $15 million in hydrogen-specific funding, $46 million for emerging opportunities and $2 million for workforce development.
The funding plan notes those amounts could change as future budgets are finalized.
The Clean Transportation Program was created in 2007 through Assembly Bill 118. AB 126 of 2023 extended the program until July 2035 and required that at least half of the program’s funding go toward projects that benefit low-income and disadvantaged communities starting in 2025.
Since its launch, the program has invested $2.3 billion into projects supporting ZEV infrastructure. As of July 2024, 63% of funds have gone to projects in communities that are disadvantaged, low-income or both.
“Approval of the investment plan reaffirms California’s commitment to funding zero-emission refueling infrastructure,” Monahan said in a statement after the vote. “There is no doubt — ZEVs are here to stay in the Golden State.”
MISO and SPP staff told stakeholders Dec. 13 that they will not perform a Coordinated System Plan in 2025 but will accept transmission issues for their annual review early in the year.
“This next annual issues review will be more of a check-the-box type of exercise than the normal, which would inform our decision to embark on a study in that particular year,” Clint Savoy, SPP manager of interregional strategy and engagement, told members during a meeting of the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).
“What we’re hoping to do with this process that we’re trying right now would result in updates to the process going forward. I think that’s something we’re going to be considering as we’re looking for ways to enhance the current CSP processes,” he added. “First off, how do we improve on the needs that we’re looking to provide solutions for and make sure we’re looking at the right things? We always consider the transmission issues that our stakeholders submit, and oftentimes those lead to more targeted studies.”
The IPSAC is scheduled to hold its annual meeting March 28, with stakeholders facing a Feb. 26 deadline to submit their issues for review. The meeting is required by the grid operators’ Joint Operating Agreement, as is a CSP every other year.
Five previous CSP studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue (JTIQ), which identified a five-project portfolio estimated to cost as much as $1.6 billion that could support up to 29 GW of interconnecting generation along their seam.
FERC approved the JTIQ framework and cost allocation in November, and the Department of Energy in 2023 awarded the portfolio $464 million under its Grid Resilience and Innovation Partnerships program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
The commission’s approval of the JTIQ process has cleared the way for RTO staffs to revise the JOA language and refocus on their Targeted Market Efficiency Project (TMEP) process. They told stakeholders the new study approach will be much broader and forward looking and will be without predefined, specific historic issues to be resolved.
The RTOs plan to begin the study work in 2025. They are collaborating on a filing timeline and promised a stakeholder review will be shared at the IPSAC’s annual meeting.
During a meeting of the SPP Seams Advisory Group, also on Dec. 13, staff reported that market-to-market (M2M) settlements with MISO have totaled $604.02 million through October in SPP’s favor.
Under the M2M process that began in March 2015, the grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements. Those settlements have steadily accrued to SPP, topping $100,000 in 2020, doubling in 2021 and doubling again in 2022.
However, the pace has slowed recently as the RTOs have added transmission to relieve congestion along the seam. Cumulative M2M payments exceeded $500 million in December 2023, but they only reached $600 million in October.
The notorious Neosho (Missouri)-Riverton (Kansas) flowgate accounted for $73 million in M2M settlements to SPP, according to a staff report to the SAG in December 2023. That number hasn’t budged since then, an indication that SPP did not have any M2M settlements on the flowgate this year.
“This issue is likely resolved by the transmission construction that occurred in the Neosho area over the last two or three years,” SPP spokesperson Meghan Sever said in an email.
THE WOODLANDS, Texas — MISO said it will leave the 10-year-old guiding principles for its market design untouched after it conducted a check-in with stakeholders to gauge whether they are still valid in a rapidly changing industry.
Speaking Dec. 10 at the meeting of the MISO Board of Directors’ Markets Committee, Zak Joundi, executive director of markets innovation and strategy, said the RTO received a “relatively small amount of written feedback” after soliciting recommended changes and updates at stakeholder committee meetings. (See Changing System Drives MISO to Scrutinize Guiding Market Principles.)
Although a few stakeholders made suggestions about adding nods to resilience or being more prescriptive about resource adequacy, Joundi said the community remains generally supportive of the principles a decade later.
“We feel like this truly covers the whole gamut,” he said.
MISO’s five guiding principles include standing up an “economically efficient” wholesale market system, fostering nondiscriminatory market participation, maintaining transparent market pricing, facilitating efficient operational and investment decisions among market participants, and aligning market requirements with reliability requirements.
In public meetings, some stakeholders have said the principles still seem to make a lot of sense even considering the transformed landscape.
However, at the Market Subcommittee’s meeting in October, the Clean Grid Alliance’s David Sapper suggested MISO consider adding an insertion encouraging coordination and collaboration among members, regulators and governments to maintain resource adequacy. Sapper also condemned the suggestion that members and states stall carbon-reduction goals for the sake of reliability, made by MISO’s Todd Ramey the previous month. (See “More Supply Alarms,” MISO Board Week Covers Supply Worry, SoCal Utility Exec Addition, $400M Budget.)
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.”
