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December 25, 2024

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Winter of NYISO Stakeholders’ Discontent over ‘Complete’ Projects

Two initiatives that have bedeviled discussion at NYISO committees in the last few weeks of the year reared their heads again at the final Budget Priorities Working Group meeting of the year Dec. 17.  

The Operating Reserves Performance Penalty and Engaging the Demand Side projects, both of which have been harshly criticized by stakeholders, drew fire yet again. (See Stakeholders Turn down NYISO Reserve Performance Penalties and Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes.) 

The issue? NYISO staff listed these projects as “complete” for the purposes of their year-end corporate incentives, which factor into staff compensation. ISO staff are awarded bonuses for completing projects on time. Stakeholders contend that these projects were not finished. 

Mark Younger of Hudson Energy Economics was particularly incensed by the reserves penalty proposal’s label, as stakeholders had declined to recommend it this month. 

“I agree there was a motion, but to call the pathetic work that the ISO did on this project a ‘completion’ is basically an indictment of the entire process,” he said. “They developed something that was very poorly designed. It got very negative feedback from a wide range of market participants and the [Market Monitoring Unit], which the ISO ignored all the way up to the point that the part they had developed had to be withdrawn.” 

The penalty was intended to address the approximately 10% of generator failures to respond to dispatch. Engaging the Demand Side was intended to be a “highly collaborative project” using stakeholders to identify gaps in demand-side resource programs. 

Kevin Pytel, director of product and project management for the ISO, seemed a little taken aback by the response to the penalty proposal, asking how many stakeholders on the call agreed. The New York Power Authority and Independent Power Producers of New York chimed in. 

“We were one of the big supporters of the Operating Reserve Performance Penalty, and we still support, kind of, what we pushed forward,” NYPA’s Tony Abate said. “But it did fail to garner substance and support from the stakeholders, so ‘completeness’ is the wrong categorization.” 

Pytel promised to take these comments to senior leadership but said that the intent of the presentation was to indicate there was going to be no further additional movement on the project until next year.  

“It is an approved project for next year,” Pytel said. “I know the removal piece and trying to iron out those details, making procedures, that is a priority for NYISO.” 

Discussion then turned to Engaging the Demand Side. 

“With respect to Engaging the Demand Side, it’s true that staff did circulate a market design concept, but it’s also true that all the affected stakeholders have rejected the concept,” one stakeholder said. “It seems like there’s a lot to be designed and discussed before you call the market design complete.” 

“We obviously got a lot of feedback on our proposal that it’s not where the stakeholder community wants it to be,” Pytel said. “My understanding also is that there is not unified agreement across the stakeholder community.” 

Pytel said that there had been movement in response to stakeholders, but several stakeholders argued that most of the proposals had come directly from staff without their input. 

“I think what you’re hearing is similar to the operating reserves” proposal, said another stakeholder who did not identify themselves. “What they are saying is that it’s not a completed product. That’s why you’re getting pushback.” 

“I will take this feedback back to the leadership team,” Pytel said. “I appreciate the comments. I’m not trying to be argumentative; just trying to talk through it so I can understand it better and articulate the concerns to the senior leadership team.” 

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Connecticut Closes the Door on 2024 OSW Procurement

Vineyard Offshore no longer plans to proceed with its bid for the 1,200-MW Vineyard Wind 2 project following Connecticut’s decision not to buy power from the project, the company said Dec. 20.

The news is a setback for Massachusetts’ efforts to scale up an offshore wind industry in the region. The state selected up to 800 MW from the project in its coordinated procurement with Connecticut and Rhode Island and had called on Connecticut or another other state or entity to pick up the remaining 400 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)

Massachusetts and Connecticut had discussed a deal for Massachusetts to buy some of the power from the Millstone Nuclear Power Plant — which is under contract with Connecticut — in exchange for Connecticut buying power from Vineyard Wind 2.

But Massachusetts proved to be unsuccessful at enticing any other bidders to procure power from the Vineyard Wind 2 project. Connecticut announced Dec. 20 its plans to select 518 MW of solar and 200 MW of battery storage from procurements administered in 2024, along with the closure of its offshore wind solicitation.

“With Connecticut’s decision today not to purchase the remaining 400 MW we are unable to contract the project’s full 1,200 MW at this time,” Vineyard Offshore wrote in a statement. “We look forward to advancing this project and participating in future solicitations to meet the region’s growing energy needs while spurring economic investment and creating thousands of American energy jobs.”

The bid cancellation leaves 2,078 MW of capacity still in play from the multistate solicitation; in September, Massachusetts selected 791 MW from Avangrid’s New England Wind 1 project and 1,087 MW from the SouthCoast Wind project, with Rhode Island selecting the remaining 200 MW from SouthCoast.

The states’ electric distribution companies still are negotiating the contracts for the two remaining projects. In November, Massachusetts electric utilities delayed the target date for finalizing the contracts from Nov. 8 to Jan. 15, with the contracts due to be submitted to the Massachusetts Department of Public Utilities by Feb. 25 (DPU 23-42).

The bids for the multistate solicitation likely will feature a major price jump compared to the first wave of offshore wind projects in the Northeast.

The best recent price comparison likely comes from the Sunrise Wind and Empire Wind projects, which agreed to contracts with New York in June with a $150.15/MWh rate. (See Empire, Sunrise Wind Back Under Contract in NY.) The 800-MW Vineyard Wind project, which was selected by Massachusetts in a 2017 solicitation and is under construction, has an average annual cost of $89/MWh (DPU 18-76, et al.).

Vineyard Offshore likely will have the opportunity to rebid Vineyard Wind 2 in 2025; Massachusetts passed a law in November authorizing multistate clean energy procurements through 2025, and state Energy Secretary Rebecca Tepper said at an event in December that her office’s statute “contemplates us doing another procurement in 2025.” (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.)

However, a new procurement alone will not solve the underlying cost issues facing New England’s offshore wind industry.

Beyond Vineyard Wind 1, neither Avangrid’s 1,080-MW New England Wind 2 project nor Ørsted’s 1,184-MW Starboard Wind were selected in the multistate solicitation, despite the authorization for procurements of up to 6,000 MW across the three states.

In shying away from an offshore wind procurement, Connecticut may have found more value in onshore projects. It selected three solar projects and a 200-MW battery project. Two of the solar projects will be located in Maine and one in Connecticut. The storage project will be sited on “an abandoned brownfield” in the state, the Department of Energy and Environmental Protection said.

“Growing and diversifying our energy supply, especially our supply of low-carbon sources of energy, is the key to bringing down the cost of electricity for Connecticut ratepayers,” said Gov. Ned Lamont (D). “These investments will also ensure we have a reliable and green grid that helps us meet demand now and well into the future.”

SouthCoast Wind Gets Federal Approval

Offshore wind advocates did receive some good news Dec. 20, with the Biden administration announcing its approval of SouthCoast Wind, the administration’s 11th offshore wind project approval to date. The administration authorized up to 2.4 GW of generation from the project. (See SouthCoast Wind Nears Federal Approval with FEIS Release.)

“As we mark this achievement, we look forward to the meaningful economic opportunities the SouthCoast Wind Project will bring to this region, both during construction and throughout the project’s lifetime,” said Bureau of Ocean Energy Management Director Elizabeth Klein.

SouthCoast canceled prior contracts with Massachusetts in 2023 due to rising project costs. Its bid for the multistate procurement indicated it would begin construction in 2025 and come online by 2030.

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NYISO MC Approves Dynamic Reserves, Regulation Multiplier Proposals

During its last meeting of the year Dec. 18, the NYISO Management Committee approved two proposals that would institute a new design for the reserve market and alter a calculation used in the regulation service market. 

Stakeholders approved tariff revisions to establish dynamic reserves, as opposed to the current static model, which bases the reserve requirement on the largest single source contingency and assumes the transmission system is fully scheduled. 

Dynamic reserves, however, can be adjusted in real time based on grid conditions. This would allow NYISO to procure the lowest-cost mix of generation to meet current system conditions. The ISO expects this to help as the system depends more on intermittent resources and during extreme weather conditions. 

The proposal has been in development since 2021, with the release of the Reserve Enhancements for Constrained Areas study, which found that the current modeling of reserve regions could not reflect the needs of the grid to respond to system changes in real time. 

Implementation of dynamic reserves is planned for 2027. NYISO is targeting the second quarter of next year to file the final tariff revisions with FERC. 

The MC also approved an update to the Regulation Movement Multiplier, a factor used to schedule regulation service providers. It represents the relationship between the number of megawatts of regulation capacity the ISO has historically sought to maintain each hour and the regulation movement megawatts instructed by automated generation control each hour. 

25th Anniversary

In his monthly address to the committee, NYISO CEO Rich Dewey noted that Dec. 1 was the 25th anniversary of the ISO. 

“There are 28 employees still around who went through that transition, and there are 22 NYISO employees that weren’t even born yet when we did that,” said Dewey, referring to the evolution of the New York Power Pool to the ISO. 

He congratulated stakeholders on their work. “Many of you also participated in the development of our rules and the formation of the ISO. … I’m looking forward to the 50-year anniversary, which is 25 short years away.” 

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California PUC Votes to Keep Aliso Canyon Open, for Now

California regulators voted Dec. 19 to keep the Aliso Canyon Natural Gas Storage Facility running with the goal of eventually shutting it down, saying the site of a massive gas leak in 2015 remains necessary to maintain reliability and reasonable rates.

The California Public Utilities Commission voted in favor requiring peak day demand forecasts to decrease to a target level before it can revisit the subject and investigate whether to shut down the controversial Southern California Gas-owned facility.

Regulators declined to vote on a separate proposal introduced Dec. 9 that would postpone a decision on the plan until March 31, 2025.

“This proceeding was really one of the most complex and technically challenging proceedings that has come before the commission in a while,” CPUC President Alice Reynolds said during the meeting.

The approved plan requires the CPUC to issue biennial assessments and recommendations for Aliso Canyon inventory in coordination with the California Energy Commission, Los Angeles Department of Water and Power, CAISO and the California Geologic Energy Management Division.

The commission can open proceedings to close the facility when the peak demand forecast for two years decreases to 4,121 MMcfd and the assessments show that reliability can be maintained, according to the order.

The current forecast peak demand is 4,618 MMcfd and is expected to decrease to 4,197 MMcfd by 2030, according to the CPUC. However, commissioners said the target could be reached sooner than the current forecasts project, pointing to local, regional and federal incentive programs to bring online clean energy resources and replace natural gas appliances.

The decision “puts forward a path to closure of Aliso Canyon that is achievable,” Reynolds said. “It’s realistic and protective of families and businesses who are struggling to pay energy bills. The path is not only achievable, but it could be shortened if reduction in gas demand is accelerated.”

“We share the commission’s and governor’s view that natural gas storage at Aliso Canyon is currently necessary to help keep customers’ electric and gas bills lower and for energy system reliability,” SoCalGas spokesperson Chris Gilbride said in a statement.

But critics argue the plan will keep Aliso Canyon open indefinitely and continue to put nearby residents at risk of methane leaks.

The Sierra Club on Dec. 3 contended in opening comments at the meeting that the proposal is “the latest in a string of commission failures” to close the facility in the foreseeable future. The organization added that the plan hinges on gas reductions occurring “due to unidentified climate policies” and said it minimizes the damage the leak did to communities living near the field.

After the proposal passed, Andrea Vega, senior organizer at Food & Water Watch, argued that the vote represented a broken promise by California’s leadership.

“This decision is cowardly, despicable and ultimately only kicks the can down the road,” Vega said in a statement. “Not only is this a slap in the face to the residents living near the facility, but it is a warning for all of us. We desperately need leaders who stand up to corporate greed, and Gov. [Gavin] Newsom has shown today that he isn’t that leader.”

Aliso Canyon’s fate has been controversial since a ruptured pipe poured more than 100,000 tons of natural gas into the air, leading to a blowout and sickening nearby residents. The leak was contained after four months in February 2016. The facility reopened at a reduced capacity in 2017. (See California PUC Proposes Aliso Canyon Endgame.)

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Berkeley Lab: Data Centers Could Need 12% of US Power by 2028

Data centers’ voracious appetite for electricity could spike more than threefold over the next four years, rising from 4.4% of U.S. power demand in 2023 to as high as 12% in 2028, according to a new report from the Lawrence Berkeley National Laboratory. 

Energy Secretary Jennifer Granholm said that demand can be met with clean energy. The report “crucially underscores why the Department of Energy has developed and is deploying technologies to enable continued economic growth across American industries,” Granholm said in a press release on the report. 

Released Dec. 20, the 2024 United States Data Center Energy Usage Report notes that total energy demand at U.S. data centers doubled between 2017 and 2023, “and continued growth in the use of accelerated servers for AI services could cause further substantial increases by the end of this decade.” 

What that means in terms of actual energy use is that data centers gobbled up 76 TWh of electricity in 2018, or 1.9% of total U.S. power demand, rising to 176 TWh in 2023, or 4.4%. Berkeley predicts future growth ranging from 325 to 580 TWh by 2028, or 6.7 to 12% of total U.S. energy demand. The power capacity required to produce that much electricity could run from 74 to 132 GW, the report says. 

The report was mandated in the Energy Act of 2020 to update a 2016 data center energy use report, also produced by Berkeley.

The new study uses a “bottom-up” approach to break down data centers’ power demand into individual components. For example, energy use varies across different kinds of servers, ranging from “conventional” single- or dual-process servers to “accelerated AI” servers, which have additional processing units that can “more quickly process large quantities of calculations in parallel.” 

Berkeley then drills down into the “wattage levels” of the different types of servers, including nameplate power, power for maximum computational levels and “typical” operational levels, and the “idle” power demand when the server is not being used. 

“Operational power in the years 2024 to 2028 is varied between 60 and 80% of the rated [nameplate] power to reflect possible differences in the future,” the report says. 

It also tracks energy use by data center type, from the smallest telecommunications servers located in closets to hyperscale centers run by tech giants like Microsoft, Google and Amazon, which have accounted for an increasing percent of demand.  

The power demand of servers in large and hyperscale data centers has been increasing steadily since 2016 but could spike in the next four years. | Lawrence Berkeley National Laboratory

Berkeley also differentiates between the power demand of AI servers used for “training” ― that is, being fed with publicly available data ― and those used for “inferencing,” which is applying those trained models for analysis or predictions. While inferencing accounted for 60% of AI servers’ power use up to 2023, the report anticipates the power demand of training servers will edge them out by 2028, rising to 50 to 53%. 

When Demand Doesn’t Show up

The report argues that its bottom-up approach could be more accurate than the projections of growing data center power demand being produced by some U.S. utilities, which typically may be based on market research estimates. 

“While not meaningless, historical utility demand forecasts consistently overestimate both peak and average demand,” the report says. 

Such overestimates may result from including data centers that have yet to choose an electricity provider, while undervaluing the capacity of renewables, the report says. Some utilities are responding to demand growth with plans to push back previously announced closure dates for coal plants and to front-load construction of new natural gas generation. 

Further, according to Berkeley, the information reported by data centers themselves does not provide the level of detail needed for better estimates of power demand. 

“Very few companies report actual data center electricity use, and virtually none report it in [the] context of IT characteristics such as compute capacities, average system configurations and workload types,” the report says. 

Because such data are often considered proprietary, the report calls for novel approaches to data sharing, such as “developing a repository for companies to provide energy-use data that would be anonymized and aggregated for public release.” 

Meeting increased power demand also will require increased collaboration between data centers, utilities, and RTOs and ISOs. The report points to the risk for other customers if a utility builds infrastructure to meet anticipated power demand from a data center that does not show up. 

Further research will be needed “to identify key risks for existing customers, data centers and utilities, explore existing contractual arrangements, and propose novel methods for risk-sharing and cost recovery,” the report says. 

Another recommendation focuses on “demand bidding,” a demand-side version of RTO/ISO resource adequacy mechanisms. “Large loads would bid their future demand needs, becoming part of a demand-side interconnection queue,” the report says. 

In her statement, Granholm noted DOE initiatives, such as its Onsite Energy Program, which offers technical assistance and market analysis to help large energy users deploy clean energy on-site; “so, data centers can be a grid asset rather than a burden,” she said. 

But ultimately the report argues for a longer-term, broader approach to data center power demand. The current surge “should be understood in the context of the much larger electricity demand that is expected to occur over the next few decades from … electric vehicle adoption, onshoring of manufacturing, hydrogen utilization and the electrification of industry and buildings.” 

“Stakeholders [should] use this relatively near-term electricity demand for data centers as an opportunity to develop the leadership and strategic foundation for an economy-wide expansion of electricity infrastructure.” 

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MISO Switches to In-house Load Forecasting to Gauge Soaring Demand

Facing proliferating load additions, MISO announced it has begun developing in-house long-term load forecasts after years of relying on outside help to form load outlooks.   

Staff made the announcement at a Dec. 19 workshop, where they shared findings from MISO’s inaugural effort to produce a 20-year forecast. MISO previously relied on a combination of a third-party consultant and Purdue University’s State Utility Forecasting Group to prepare long-term load forecasts.   

Executive Director of Market and Grid Research DL Oates said “it’s pretty clear” the load growth picture in the footprint is changing rapidly, propelled by a manufacturing revival, transportation electrification and data center growth spurred by rapid AI advances. 

MISO forecasts its 638 TWh of gross energy in 2024 could grow to anywhere between 921 TWh and 1,225 TWh in 20 years, driven by data centers, electric vehicles and a burgeoning green hydrogen industry.  

Executive Director of Transmission Planning Laura Rauch said MISO’s load growth forecasting will factor heavily into MISO’s three, 20-year futures scenarios, which are used to inform long-range transmission planning. The grid operator has committed to revising its futures throughout 2025 to account for more load and more clean energy transformation. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.)  

MISO engineer Brad Decker said MISO and the rest of the country are exiting a roughly 15-year period of stagnant, average 0% load growth. MISO now expects annual load growth of 1 to 2% through 2044.  

MISO believes load growth from electrification to be about three times higher than previously projected through long-term forecasts. Decker said the steeper growth rate over the next 20 years is due to the “gold rush” to data centers, He said MISO is gearing up for anywhere from 19 to 30 GW of new data center additions by 2040.  

Within MISO, Iowa, Minnesota and Indiana will lead in data center growth, Decker said, due to availability of land, interconnection opportunities and fiber connectivity. He also noted that electric vehicles are expected to reach cost parity with gas vehicles in the next few years. 

However, Decker said MISO won’t rule out an economic slowdown that could suppress growth. He said though he thinks much of the load growth will come to pass, there are some “cracks” forming through the U.S., with consumers and companies carrying higher debt. MISO also allowed that most growth in manufacturing and industry will take place post-2030 and is “highly contingent on continued policy support” through federal laws.  

Decker said he expects some of the mystique around load growth from data centers to evaporate over the next few years. He said pinning down load growth from electric vehicles a few years back was similarly nebulous.  

“Load has been relatively flat, but that paradigm is coming to an end,” MISO Strategic Insights Manager Dominique Davis said. She said MISO will continue researching to better understand future demands and provide “directional insights” to its members. She said MISO will incorporate the latest macroeconomic assumptions and analyses that seek to capture fast-moving industry trends.  

Davis added that MISO will look for ways to add machine learning and more automation in its forecasting process, perhaps leading to programmed data exchanges with stakeholders, load-serving entities and other third parties who help shape the forecasts. 

Davis also said the RTO has more work to do to understand to what extent distributed energy resources will offset load growth.  

MISO is taking stakeholders’ opinions on its internal and more comprehensive load forecasting through Jan. 15.  

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Consumer Groups Seek Independent Oversight of Local Tx Planning

Twenty-two consumer and advocacy groups from across the U.S. filed a complaint with FERC Dec. 19 contending that the local transmission planning processes overseen by the commission demonstrate widespread inefficiencies that needlessly incur costs for electricity ratepayers.

The Industrial Energy Consumers of America (IECA), American Forest & Paper Association, R Street Institute, Public Citizen, Maryland Office of People’s Counsel, Pennsylvania Office of Consumer Advocate and other consumer groups filed the lengthy complaint against ISO/RTOs, utilities outside the organized markets and jurisdictional utilities with local planning processes.

“FERC’s stated mission is to ‘assist consumers in obtaining reliable, safe, secure and economically efficient energy services at a reasonable cost through appropriate regulatory and market means, and collaborative efforts,’” IECA President Paul Cicio said in a statement. “FERC has failed in its mission to deliver ‘just and reasonable’ transmission rates.”

He added that while the commission has required regional planning for three decades as an essential component to just and reasonable rates, it has continued to allow individual transmission owners to plan electric infrastructure critical to the nation’s economy and security based on their individual corporate interests and increasing their profits.

“Complainants demonstrate that provisions in the tariffs of the named public utilities and the RTOs/ISOs inappropriately authorize individual transmission owners to plan FERC-jurisdictional transmission facilities at 100 kV and above without regard to whether such local planning approach is the more efficient or cost-effective transmission project for the interconnected transmission grid and cost-effective for electric consumers,” the complaint said.

“Local planning, coupled with the absence of an independent transmission system planner, has produced inefficient planning and projects that are not cost-effective, resulting in unjust and unreasonable rates for both individual projects and cumulative regional transmission plans and portfolios,” it said.

FERC has a statutory requirement to protect consumers from excessive rates and charges, and is required to protect the public interest, as distinguished from the private interests of utilities, the complaint said.

“The commission has not fulfilled its statutory obligation to ensure just and reasonable, non-discriminatory transmission rates and practices affecting those rates because existing local planning tariffs allow individual transmission owners to plan FERC-jurisdictional transmission facilities at 100 kV and above without regard to whether it is the right project for the interconnected grid, resulting in unjust and unreasonable rates,” the complainants wrote.

FERC discussed the drawbacks to such local transmission planning processes in Order 1920 but did not change anything, saying such concerns were outside the scope of the proceeding that produced the transmission planning rule, they contended.

‘Shareholder Directives’

The complaint notes that PJM’s territory has 1,584 locally planned transmission projects valued at $18.1 billion with expected in service dates from Jan. 1, 2024, until Dec. 31, 2028.

“Those projects, like locally planned projects across the country, receive only a superficial, if any, independent review and thus there is no assurance that they represent efficient or cost-effective projects for consumers,” the filing said. “Importantly, this complaint does not challenge the rates for any specific locally planned project as unjust and unreasonable; instead, this complaint alleges that the cumulative effect of tariff provisions allowing local planning of transmission projects 100 kV and above results in unjust and unreasonable transmission rates.”

According to the complaint, the overbuilding is worse for smaller transmission lines from 100 kV to 230 kV, but it argues that the entire grid is being overbuilt. It contends that the “massive spike in consumer expenditures for locally planned transmission” is the result of incumbent utilities responding to “shareholder directives.”

“The investor-owned utilities do not hide this fact, repeatedly telling Wall Street analysts the amount of commission-jurisdictional capital expenditure (CapEx) expected over the coming years in order to bolster stock prices,” the complaint said. “The investor-owned utilities could only know the level of FERC-jurisdictional transmission CapEx if they also know that the jurisdictional transmission planned will inure to their rate base because they will not be subject to any competition to garner those projects, and thus exists the incentive for self-planned transmission.”

The complaint proposes to fix the status quo with a requirement that all regional planning be conducted through an “independent transmission planner” to ensure the best project for consumers and the interconnected grid is developed in the regional plan, Cicio said.

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Oklahoma Gov. Stitt Threatens to ‘Unplug’ from SPP

Oklahoma Gov. Kevin Stitt’s (R) recent threat during a television interview to “unplug” from SPP may sound like political rhetoric designed to curry favor with his constituents, but the Arkansas-based grid operator is taking the statement seriously. 

Calling himself the “most pro-oil and gas governor in the country,” Stitt told Oklahoma City political analyst Scott Mitchell during his local “Hot Seat” program that the “feds coming in demanding eminent domain” to build transmission lines is why he wants to “pull that back from the feds, pull back from SPP.” 

“I just don’t want to have to play ‘Mother, may I’ to the Southwest Power Pool … before I add energy to my own grid,” Stitt said. “That’s where I have a problem with the Southwest Power Pool. So, I’m looking at unplugging from them.” 

Stitt was apparently conflating the U.S. Department of Energy’s National Interest Electric Transmission Corridors (NIETCs) with SPP’s transmission work. One of those corridors, the 645-mile Delta-Plains corridor from Little Rock, Ark., through Oklahoma, drew strong political and public opposition in the state over eminent domain concerns. 

“I won’t let anyone steamroll Oklahomans or their private property rights,” Stitt posted on X. “The feds don’t get to just come here and claim eminent domain for a green energy project that nobody wants.” 

When the corridor was not included among the three corridors that advanced to the next phase, Stitt returned to X. “Good riddance. Another win for Oklahoma!” he crowed. (See DOE Cuts NIETC List from 10 to 3 High-priority Transmission Corridors.)

Still, his comments drew the attention of SPP. Staff have been working with Stitt ever since, providing a statement to Oklahoma media and clarifying that they have nothing to do with the NIETC process. They have also been working to answer a list of questions the governor has submitted to the RTO. 

“We’re working to provide him the information he’s seeking, and we hope to provide that to him within the next several weeks,” COO Lanny Nickell, SPP’s newly minted CEO-in-waiting, told RTO Insider. (See related story, SPP Names COO Nickell to Replace Sugg as CEO.) 

So, can Stitt unplug his grid from SPP? It would likely require legislation directing electric utilities to withdraw from the RTO. But that’s easier said than done. 

First, there’s the matter of the substantial termination fees the state’s utilities would have to pay to leave SPP’s membership. Oklahoma would then have to figure out the construct under which to operate its own market and how to perform the services SPP currently provides. That would include reliability coordination, transmission planning and dispatch, crafting market rules and providing open access. 

While incurring significant costs standing up a replacement to SPP, Oklahoma would also lose the benefits of belonging to a RTO, where costs are socialized among its members. The grid operator’s 2021 Value of Transmission study found that the $3.4 billion of new transmission projects placed in service between 2015 and 2019 will result in more than $27.2 billion in savings and benefits over the next 40 years, a benefit-cost ratio of 5.24. 

Those numbers and other metrics are some of what SPP is providing to Stitt, Nickell said. He pointed out that every expansion of SPP’s membership has resulted from utilities, states and regulators determining that RTO membership provided significant net benefits through increased reliability, more affordable wholesale electricity and offering members’ input in developing solutions that benefit the entire footprint. 

In the meantime, SPP is continuing to talk with Stitt’s office to “strengthen our mutual understanding” of how the RTO can continue to keep the state’s lights on “affordably and reliably,” Nickell said in his statement. 

“We’ll continue to work with Gov. Stitt, as we do with all legislators and regulators across our service territory, to ensure the benefits of SPP membership continue to far outweigh the costs,” he said. 

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LPO Finalizes Major Loans to Ford, Stellantis for EV Battery Plants

The U.S. Department of Energy’s Loan Programs Office is locking in billion-dollar federal investments aimed at building out a domestic battery supply chain that could accelerate the rollout of new electric vehicle models by major automakers.

On Dec. 16, LPO announced it had finalized a $9.63 billion loan to BlueOval SK, a joint venture between Ford Motor Co. and South Korean battery maker SK On. The company is building three mammoth battery factories, two in Kentucky and one in Tennessee, which eventually will produce more than 120 GWh of batteries per year, to be used in Ford and Lincoln EV models.

The second finalized loan, announced Dec. 17 for $7.54 billion, is going to StarPlus Energy, a joint venture of Stellantis and Samsung. StarPlus is nearing completion of the first of two EV battery factories in Kokomo, Ind., with a total annual battery capacity of 67 GWh, or the equivalent of about 670,000 EVs.

BlueOval also has two of its three factories getting ready for production in 2025, one each in Kentucky and Tennessee. While the company says construction of the second Kentucky plant is “on schedule,” work on the project was put on hold in 2023 after Ford pulled back on its planned rollout of EVs because of lower-than-expected demand.

The BlueOval and StarPlus loans are, respectively, the largest and second largest that LPO has made under its Advanced Technology Vehicles Manufacturing program, which is designed to “provide low-cost debt capital for fuel-efficient vehicle and eligible component manufacturing in the United States,” according to an LPO fact sheet.

In December 2022, LPO also closed a $2.5 billion loan to Ultium Cells, the battery joint venture of General Motors and LG Energy Solutions, again to fund battery factories in Michigan, Ohio and Tennessee.

In BlueOval’s case, the loan will help the company “do more, faster, increasing liquidity and optimizing financial flexibility,” CFO Jiem Cranney said in an email to NetZero Insider.

“We have invested more than $11 billion in the construction of three 4 million square-foot facilities, installation of equipment and strategically building our workforce,” Cranney said. “This loan, which will be repaid with interest, keeps us on pace for an on-schedule start to production and allows BlueOval SK to sustain and grow our presence in the EV battery space.”

Building out a domestic EV battery supply chain is seen as increasingly important for the U.S. to successfully compete against China, which controls 70 to 90% of different parts of global battery supply chains, according to a recent analysis from the Carnegie Endowment for International Peace. Chinese EVs are also gaining ground in Southeast Asia and Mexico, with smaller, less expensive models, in some cases priced under $20,000.

While U.S. tariffs will keep Chinese EVs out of the domestic market at least in the near term, the loans are “essential to getting [EV manufacturers] to choose the United States of America,” LPO Director Jigar Shah told Reuters. “When you look at the competition that we have from China, it is very clear to me that they have used low-cost debt for a very long time to promote a lot of manufacturing capacity that has hollowed out many communities in Kentucky, Tennessee and other states around the country.”

US Market

A robust domestic battery supply chain is also seen as critical for raising the confidence of both automakers and consumers in a strong U.S. market for electric vehicles. Despite their large investments in battery factories, both Ford and Stellantis have been cautious, if not slow, to expand their EV offerings.

Ford continued its EV pullback in August, announcing a shift in its sales strategy to focus on the commercial vehicle market and the production of hybrid vehicles, which have seen rising sales across the auto industry. Although Ford’s Mustang Mach-E has led the U.S. market for crossover electric SUVs this year, sales of the popular model fell 10% in the third quarter, according to Ford Authority, an industry trade publication.

Tesla still leads the new EV market in the U.S., with 49.5% of sales, but Ford is second, with 6.8%, according to Cox Automotive.

Stellantis, which owns the Jeep, Chrysler and Dodge brands, only recently launched its first EV for the U.S. market, the Jeep Wagoneer S. It has also announced plans to start production in early 2025 of its new electric Dodge Charger, which the company is billing as the “the world’s first and only electric muscle car.”

Stellantis grabbed additional headlines in early December with the announcement that it is partnering with Houston-based Zeta Energy to develop lithium-sulfur batteries, which could provide greater range and faster charging times, according to the Stellantis press release.

Neither Stellantis nor StarPlus responded to NetZero Insider queries about their plans for the Kokomo factories and whether they would be used to produce lithium-sulfur batteries.

EV Chargers Plugging Along

While much uncertainty surrounds the fate of federal funding for EVs during the second Trump administration, the U.S. market continues to rack up increasing sales and steady growth.

In 2024, EVs accounted for about 8% of all new auto sales in the U.S., according to year-end figures from Cox. Fourth-quarter sales of 356,000 EVs represent an estimated increase of 12% year over year.

New EV sales for 2024 are expected to hit 1.3 million, said Stephanie Valdez Streaty, the company’s director of industry insights.

Cox is predicting that EVs will “tip over 10%” of the new car market in 2025, with “the introduction of new models, improved charging and advancements in battery technology,” Valdez Streaty said during a Dec. 17 webinar. Expanding the charging network will remain critical to overcoming consumers’ charging anxiety, which could be threatened if the funding for the National Electric Vehicle Infrastructure program is “redirected or eliminated,” she said.

The NEVI program, funded with $5 billion from the Infrastructure Investment and Jobs Act, provides formula-based allocations, typically in the millions, to states to install direct current fast chargers every 50 miles along “fueling corridors,” which typically follow interstate and state highways. To date, 171 NEVI chargers are online at 41 stations across 12 states, according to the latest figures from the Joint Office of Energy and Transportation.

The U.S. now has more than 205,000 public chargers, so EV drivers on 60% of the country’s most heavily trafficked highways can expect to find a public charger every 50 miles, the office says.