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December 24, 2024

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SPP Briefs: Week of Dec. 16, 2024

DALLAS — SPP’s Resource and Energy Adequacy Leadership (REAL) Team closed out the year by taking two actions related to the long-term planning reserve margin (PRM). 

The team Dec. 18 unanimously approved a long-term policy paper intended as a guide for SPP staff as they continue to develop policy and additional work plans on the subject. The paper outlines the framework for establishing long-term planning horizon PRM requirements to minimize revisions to the requirements with adequate advance notice leading up to the applicable operating season. 

Team members debated whether the paper captures all the risk factors, with some urging a conversation around the possible variances that could occur. 

Natasha Henderson, SPP’s director of system planning, said she received offline feedback that the paper presents a buffer of sorts, to which she responded, “No.” 

“We are really looking at two different types of risks when we move from the long-term planning horizon to the real time in operations,” she said. “What happens if we set something five years out and things change between our assumptions and resource mix and the interaction of the resource mix and load. If something changes that meets the one-day-in-10 [reliability] standard that we were planning to, we may not have actually been planning to that. That’s the nature of risk.” 

She said other comments centered on what the right practice may be, instead of just arbitrarily increasing the PRM. 

“All that the paper is saying is that we need to understand what that risk is,” Henderson said. “The mitigations of that risk would happen later, after a lot of discussion that would include the discussion of affordability.” 

The grid operator recently won FERC approval of a 36% PRM for the winter season, effective 2026/27. It has a 16% margin for the summer season, effective 2026. (See FERC Approves SPP’s Winter RA Requirement.) 

The proposed policy paper includes edits from the Kansas Corporation Commission’s Andrew French, who described another grid operator’s process of setting the PRM as wildly inconsistent. 

“To increase planning certainty, there should be appropriate consideration of risk in setting long-term PRM requirements, so that the need for subsequent adjustments to those established requirements is minimized,” he wrote. “However, all stakeholders should recognize longer-term planning intrinsically involves more uncertainty. SPP can provide best estimates of long-term resource needs, giving [load-responsible entities] more planning information, but LREs share the obligation to plan for the future.”

The REAL Team also endorsed the Supply Adequacy Work Group’s recommendation of 2029 PRM values set at 38% for the summer and 17% for the summer. The SAWG based its recommendations on the 2024 submitted forecasts for the resource and load mix, which used SPP’s 2023 loss-of-load expectations study. 

Changes in proposed load (increased) and the resource mix (thermal increased, wind resources dropped) resulted in different PRMs for the 2029 study year. However, the RTO’s staff said they could support SAWG’s recommendation because it can evaluate 2030 in the 2025 LOLE study and set a 2030 PRM based on the long-term policy paper. 

Nickell Looks Forward as CEO

The REAL meeting came the day after SPP announced Lanny Nickell would become the grid operator’s CEO in April. That gave the team’s lead, South Dakota Public Utilities Commission Chair Kristie Fiegen, an opportunity to invite Nickell to make his first public comments to stakeholders. (See SPP Names COO Nickell to Replace Sugg as CEO.) 

“One of the favorite things about my experience at SPP, and I’ve been here 27 and a half years, has been working with stakeholders. It’s just what I enjoy doing,” he said.  

Nickell added that he cares “deeply” about SPP and its success, lumping employees, members and their customers together. 

“We’ve got a lot of work ahead of us. We’ve got some very real challenges,” he said. “This is the right committee working with the SAWG, working with [state regulators] resolving those challenges, because that’s where the majority of our challenges are. I’m excited to be able to continue to work with you all to figure those things out, and I think we’re going to be successful, and I’m excited about the future.” 

Markets+ Strengthens Participant Engagement

The Interim Markets+ Independent Panel (IMIP), composed of three independent SPP board members, approved two measures Dec. 19 to provide greater cooperation between the IMIP and western state regulators and establish a policy for appeals to the RTO’s board. 

The IMIP signed off on a joint resolution formalizing an agreement with the Markets+ State Committee (MSC) to participate in each other’s meetings, with allocated time on their corresponding agendas, and to host joint in-person and/or virtual meetings to address any issues during the development and operation of Markets+. 

The MSC, a group of regulators from 13 states in the West and the Great Plains, raised the need for ongoing engagement in late 2023. The Markets+ Participant Executive Committee (MPEC) eventually handed it to the Markets+ Interim Governance Task Force (MIGTF). 

“This was kind of dumped in their lap, and they didn’t know what to do with it,” said MSC Chair Nick Myers, with the Arizona Corporation Commission. 

It took a 30-minute conversation between Myers and IMIP Chair Steve Wright to iron out the resolution. 

“This hopefully resolves any concerns that are out there about how we will work together going forward,” Wright said. 

The IMIP also approved a policy brought forward by the MIGTF and MPEC to address interactions between the Markets+ Independent Panel (MIP) and the SPP board. The policy includes a process under which the IMIP and MIP can submit appeals to the board.  

The MIP will replace the IMIP by the time Markets+ is up and running, currently targeted for early 2027. It will be allowed to appeal decisions on the same issue multiple times to the board. 

ASPC’s Myers: FERC Order Close

FERC is close to filing its response to SPP’s filing to the commission’s finding that the RTO’s Markets+ tariff submittal is deficient, Myers told the MSC on Dec. 20. 

Myers, part of a recent Western Interstate Energy Board delegation to FERC’s offices in Washington, D.C., said that after discussions with staff, he’s hopeful the commission will rule on the tariff in January. SPP submitted its response to FERC’s deficiency finding in September, asking for a response by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

“I impressed upon them that the MSC really didn’t have too much opposition to that tariff, which is the reason why we didn’t necessarily file comments,” Myers said. “They were very receptive of that and thought it was great that the states were in agreement with the tariff overall. I did get … that it’s a top priority and that they’re kind of in the final stages of it.” 

Potential Competitive Upgrades

Two recently approved 345-kV transmission projects potentially meet the requirements for competitive upgrades, SPP said Dec. 16.  

The projects in question — Belfield-Maurine-New Underwood-Laramie River, from the Dakotas into Wyoming, and Elm Creek-Tobias in Nebraska — also include upgrades that don’t qualify as competitive because they interconnect to existing non-competitive facilities. Those upgrades will receive notifications to construct with conditions (NTC-C). 

The non-competitive upgrades will require refined cost estimates that will affect the projects’ overall status. Under SPP’s tariff, an entire project could be re-evaluated if the non-competitive refined cost estimate is out of bandwidth and is not considered fully approved for construction. 

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Texas PUC Shelves PCM Design Over Lack of Benefits

The Texas Public Utility Commission has shelved the market design it once favored, agreeing with staff’s recommendation that the performance credit mechanism (PCM) results in “minimal” additional resource adequacy value.

In a memo filed before the PUC’s Dec. 19 open meeting, commission chair Thomas Gleeson said he concluded the PCM, “as currently designed,” wouldn’t provide “the reliability benefits needed in the ERCOT market.” He said it would be “appropriate” to reconsider the PCM in the future,” but that the commission’s “collective resources are best directed toward implementing other market design initiatives” (55000).

“The outcome is what it is,” Gleeson said during the open meeting after gaining agreement from his fellow commissioners. “But the work was tremendous, the analysis was tremendous, and that got us to the decision that we needed to make.”

“There are variables that are in the PCM, there’s things that we can come back if later needed to learn from … and definitely something that is not thrown away, just put on the shelf,” commissioner Courtney Hjaltman said. “[Let’s] see what other things are in the market, and we can come back and learn from those things.”

The commission in August directed ERCOT and the Independent Market Monitor to complete updated assessments of the PCM’s cost to and its effects on the market. Staff reviewed those assessments before making their recommendation.

The PCM was designed to incent more gas generation by awarding thermal generators credits based on their performance during a determined number of scarcity hours. Those credits would be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

However, ERCOT’s assessment, conducted with the Energy and Environmental Economics (E3) consulting firm, found that the market would hit a $1 billion gross cost cap imposed in 2023 by the Texas Legislature every year and add only about 800 MW of dispatchable generation. It said the cap “significantly limits the effectiveness of the PCM.”

The IMM said the “novel” design would provide a new source of revenue for generators that would increase ERCOT’s capacity margin and the costs to customers but reduce shortage revenues. Eventually, the higher capacity margins would reduce the frequency of shortage pricing, with the net costs falling to $350 million to $725 million annually.

“Good riddance,” energy consultant and former PUC and FERC staffer Alison Silverstein said. She agreed with the PUC’s decision to wait on real-time co-optimization and better battery rules, targeted for implementation in December 2025, and other measures before revisiting the PCM.

The grid operator also is working on a standalone dispatchable reliability reserve service (DRRS), a non-spinning reserve service subtype as a result of a new law, and analyzing ancillary service demand curves.

“If you’re going to mess with the market, the juice should be worth the squeeze,” Silverstein told RTO Insider. “The limits on PCM make it unlikely to be an effective gas plant subsidy, so why bother?”

Doug Lewin, Stoic Energy’s founder and principal, also agreed with the PUC’s decision.

“Capacity market constructs do too little, if anything, for reliability for their massive cost,” he said. “I hope now the commission, ERCOT and stakeholders can focus on more important things and stop wasting time arguing about capacity market design.”

ERCOT spokesperson Christy Penders said in an email that while the PCM didn’t provide enough benefits to move forward for the time being, “We continue to work with stakeholders on market solutions to enhance the reliability of the Texas power grid.”

ERCOT to Pursue Braunig MRAs

ERCOT General Counsel Chad Seely told commissioners that staff expects to execute a reliability must-run agreement with San Antonio’s CPS Energy within weeks for its Braunig Unit 3 gas resource. The grid operator says the capacity is needed to address transmission reliability until several South Texas projects are completed by summer 2027. (See ERCOT Board of Directors Briefs: Dec. 2-3, 2024.)

Seely said staff are continuing discussions with CPS, CenterPoint Energy and Life Cycle Power over moving 15 large generators and their 450 MW of capacity from Houston to distribution sites in the San Antonio area. The generators, which range in size between 27 and 32 MW, would provide a less expensive alternative to the $56 million CPS says it will take to overhaul and continue running Braunig’s other two units.

The San Antonio municipality told ERCOT earlier this year it intended to retire all three 1960-era units in March 2025.

“We think technically, this is a very feasible option and will provide a better, reliable solution than moving forward with an RMR agreement for Units 1 and 2,” Seely said.

In the interest of time, ERCOT issued a request Dec. 20 seeking one or more must-run alternatives to the potential solution being negotiated.

CenterPoint Executive Vice President Jason Ryan told the PUC that if the generators are moved to San Antonio before the summer, its Houston-area customers won’t be charged for the units, and the utility won’t receive any revenue or profit from them.

“This whole time, it’s been our priority to make sure that we can bring to the table a Texas solution … and at the same time [we’re] providing that Texas-based solution, making sure that our customers see a rate reduction as a result.”

CenterPoint leased the generators for $800 million in 2021 following that year’s winter storm that nearly collapsed the ERCOT grid. The large generators turned out to be anything but mobile and when they went unused in Hurricane Beryl’s aftermath, CenterPoint came under fierce political and customer criticism.

ERCOT’s Kristi Hobbs, vice president of system planning and weatherization, said the ISO’s twice-yearly Capacity, Demand and Reserves report’s December release will be delayed into 2025 “to ensure we get it right.” A recent protocol change (NPRR1219) extends the seasonal CDR reporting to all four seasons and adds unavailable switchable generation resource capacity.

In other action, the PUC:

    • Adopted new requirements for utilities in ERCOT that lease and deploy mobile generation facilities. The rule is a result of the 87th Texas Legislature’s House Bill 2483 (53404).
    • Approved staff’s review of ERCOT’s ancillary services (AS) that was conducted with the grid operator’s staff and the Independent Market Monitor. The review found that ERCOT’s current set of AS and the future DRRS are enough to comply with NERC requirements and recommended only minor changes (55845).
    • Again tabled Entergy Texas’ proposed system resiliency plan that would implement six resiliency measures over a three-year period at a cost of $335 million. At issue is Entergy’s request for conditional approval of $198 million of projects that would become part of the plan if the utility receives grants under the Texas Energy Fund’s Outside ERCOT Grant Program (56735).
    • Rejected a joint petition by two retail advocacy groups requesting ECRS be designated as an ancillary service incurring charges beyond a retailers’ control for existing contracts executed on or before June 9, 2023 (55959).
    • Approved the final draft of its biennial agency report to the Texas Legislature. The report must be submitted by Jan. 15 (56335).

Commissioner Lori Cobos adjourned the meeting, her last as a PUC member. Cobos, the last of the three commissioners appointed in 2021 to replace the three previous incumbents following that February’s disastrous winter storm, announced her retirement in November. (See Texas PUC’s Cobos to Leave Commission.)

Cobos battled her emotions as she thanked fellow commissioners, the PUC staff and the state’s political leadership, calling her appointment the “honor of a lifetime.” Her audience included former FERC and PUC chair Pat Wood.

“I am tremendously grateful for this opportunity to have served on the PUC,” Cobos said.

Alluding to Cobos’ focus on building transmission, Hjaltman said, “We’re going to hopefully do you proud with everything and your legacy of transmission and get those projects done for you.”

Gleeson revisited his comments from Jimmy Glotfelty’s departure Dec. 12 and thanked Cobos for “all the work you did on my Permian Basin reliability project.”

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Study Calculates Trillions in Economic Benefits from IRA

A new report on the Inflation Reduction Act — issued as the IRA faces a potentially existential threat — finds that it could boost U.S. GDP by $1.9 trillion over the next decade. 

The study, commissioned by the American Clean Power Association and conducted by consulting firm ICF, said the economic benefits will extend across the energy sector and beyond, to transportation, buildings and manufacturing. 

“Economy-wide Impacts of the Inflation Reduction Act Energy Provisions” estimates that the IRA’s roughly $740 billion in tax credits will: 

    • motivate approximately $2 trillion in capital investment; 
    • spur $3.8 trillion in spending attributable to the IRA; 
    • support 13.7 million job years from 2025 to 2035; 
    • contribute to the clean energy workforce expanding from 3 million in 2022 to 6.5 million in 2032; 
    • increase Americans’ disposable income by nearly $77 billion per year; 
    • eliminate emission of 4.1 billion metric tons of carbon dioxide equivalent; and 
    • yield more than $1 trillion in emissions benefits. 

That is a 4X return on taxpayer investment, the report concludes, with additional consumer savings from lower operating costs for higher-efficiency buildings and vehicles. 

In the 28 months since the IRA was signed into law, “The clean energy tax credits have significantly increased domestic energy production, revitalizing communities across the country and lowering consumer energy bills,” American Clean Power Association CEO Jason Grumet said Dec. 19 in a news release announcing the study.  

“By supporting our nation’s diverse array of energy resources, the IRA is strengthening our national security and enhancing economic competitiveness.” 

That message directly aligns with some of the key stated priorities of President-elect Donald Trump, who has repeatedly attacked climate-protection initiatives including the IRA, a signature achievement of President Biden. 

The IRA passed without a single Republican vote, and Republicans soon will be in a position to derail the remainder of the 10-year plan. But the economic benefits so far have accrued disproportionately to Republican congressional districts, and there is widespread speculation that any attempt at large-scale cancellation or clawback by Republican leadership will encounter resistance from the rank and file. 

This gives some IRA proponents hope that any changes will be made with a scalpel rather than a chainsaw. 

Introducing the study, ICF wrote that it sought to estimate incremental economy-wide impacts from the IRA — effects beyond those attributable to state policies and clean energy activity that would have occurred without the IRA. 

It reviewed all IRA incentives in key areas: power, transportation, buildings, sustainable aviation fuel, hydrogen and manufacturing. Then it projected the incremental impacts of the IRA on each sector. 

The accounting of the models includes not just positive impacts but negative factors such as the cost of funding the IRA, cost of private sector funding and cost of displaced economic activity such as fuels. 

Supporting data include cost-benefit analyses, job creation due to investments made since 2022 and economy-wide employment impacts. 

The U.S. Chamber of Commerce, Edison Electric Institute, National Electrical Manufacturers Association, National Hydropower Association and Nuclear Energy Institute joined with American Clean Power in endorsing the findings of the report. 

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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 (light and dark blue in the charts above) 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.