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January 24, 2025

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PJM in Discussions with Gov. Shapiro on Capacity Price Cap

VALLEY FORGE, Pa. — PJM is in discussions with Pennsylvania Gov. Josh Shapiro to work toward a resolution on his complaint to FERC asking it to lower the price cap of the RTO’s capacity market, the Members Committee heard Jan. 23 (EL25-46). 

The discussions also follow a letter Shapiro wrote to the PJM Board of Members requesting that it intervene to avoid an “unacceptable” $20.4 billion increase in capacity market prices or the commonwealth may “re-evaluate” its relationship with the RTO. (See Shapiro Warns of ‘Reevaluation’ of PJM if Capacity Prices not Addressed.) 

PJM General Counsel Chris O’Hara told the committee that the discussions have included the design of a price cap, as well as the concept of a price floor. He said PJM also has emphasized to the governor that any market changes must consider the need to attract investment in the RTO while also balancing consumer rates. 

“We want to make sure you are all aware of these discussions,” he told stakeholders. 

Responding to questions on whether there is a timeline for PJM to reach a settlement or how the discussions interact with the schedule of the 2026/27 Base Residual Auction, O’Hara said the RTO is moving expeditiously. The auction is scheduled to be conducted in July and in several filings seeking to revise elements of the capacity market, PJM has requested orders by Feb. 21 to ensure it has time to implement the changes. 

“We are aware of the auction schedule, and we are moving with haste, but there is no date certain,” he said. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if it was appropriate for PJM to be discussing market rules with a nonmember, particularly when the changes could affect all market participants. O’Hara responded that PJM will continue to have discussions with membership as well. 

Shapiro requested the auction’s price cap be reset to 1.5 times the net cost of new entry (CONE); the status quo is the greater of gross CONE or 1.75 times net CONE. On Jan. 21, FERC granted a joint motion that Shapiro and PJM filed asking for a one-week extension on the RTO’s deadline to respond. 

“The requested extension will allow the joint parties to engage in discussions concerning the complaint before any answers are filed,” they said in their motion. 

PJM responded to Shapiro’s letter on Jan. 16, saying it has yet to take a position on the substance of his complaint. 

“We share your concern for consumer cost increases resulting from the region’s supply/demand challenge,” PJM wrote. “We are simultaneously concerned about market changes that could serve to thwart new generation entry. This new entry is needed to preserve system reliability and ultimately reduce costs for consumers. PJM is very willing to have discussions about how these two concerns can simultaneously be addressed.” 

Since Shapiro’s complaint was filed, the governors of Maryland, Delaware, Illinois and New Jersey also have sent letters to PJM and FERC urging action. 

“As one of the original members of PJM, New Jersey has long worked in partnership with PJM to pioneer new and innovative approaches to provide our residents with reliable and affordable power, most recently exemplified with our work together on the State Agreement Approach,” Gov. Phil Murphy said in a Jan. 21 letter to the RTO. “That long partnership has become frayed in recent years as PJM continues to take actions that are incongruent with our energy policy and the best interests of our residents. I am calling on you to help repair that partnership and work with New Jersey and other interested states to resolve this matter.” 

In his own letter, Maryland Gov. Wes Moore argued that a lower price cap is needed to prevent a growing affordability problem from worsening in the next capacity auction. 

“I strongly urge you to make the requested adjustments to help contain costs to Maryland households, as well as households throughout PJM, particularly in light of the fact that the previous suite of changes to risk modeling and capacity accreditation developed under PJM’s Critical Issue Fast Path contributed to the results of the last auction,” he wrote. 

On Jan. 17, Illinois Gov. JB Pritzker and former Delaware Gov. Bethany Hall-Long (whose term ended Jan. 21) joined Murphy and Moore in a letter to FERC arguing that the temporary change would contain auction prices, as barriers to new entry prevent resources from responding to high prices and a large number of rule changes are being considered by the commission. 

“The proposed temporary modification to the price cap ensures that prices do not reach unjust and unreasonable levels despite the structural limitations in today’s marketplace preventing a pronounced market response to elevated prices,” they wrote. “This measure is also warranted given the unusually large number of emergency reforms PJM has proposed for the upcoming 2026/2027 auction, as well as the significant changes implemented in the 2025/2026 auction.” 

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Weather, Supply Chain Top SERC Risk Rankings

Extreme weather, supply chain constraints and resource uncertainty top the risks facing the SERC Reliability footprint in the next two years, presenters said at a Jan. 23 webinar detailing the regional entity’s latest Regional Risk Report.

SERC publishes the regional risk report every two years to supplement NERC’s Reliability Risk Priorities Report; the ERO’s report is published in odd-numbered years, while SERC’s is released in even-numbered years.

“I can’t really think of anything better for our industry and our [power] grid than this report,” Tim Ponseti, SERC’s vice president of operations, said at the webinar examining the report. “It’s foundational for everything we do here at SERC. It feeds into the NERC risk report, it feeds into our outreach, our priorities, our state programs, our assistance programs — so many things.”

The report identified 10 key risks facing entities in SERC’s footprint. Each risk was nominated by stakeholders via a form on SERC’s website and reviewed by the RE’s Reliability Risk Working Group and Technical Committee to determine whether or not to add it to SERC’s risk registry. Their ranking was determined by subject matter experts evaluating each risk across 15 impact areas.

First on the list were supply chain constraints, which include both the risk of vendors introducing vulnerabilities to products used by grid operators — whether intentionally or not — and of delays to projects from shortages of needed materials.

These conditions can arise from a number of factors, the report found, including overreliance on a limited number of suppliers that can be disrupted by cyberattacks, natural disasters and geopolitical tensions. The report said SERC’s Engineering Committee “has identified significant supply chain risks that threaten the stability of the energy sector” and recommended several mitigation strategies, such as diversification of suppliers, enhanced cybersecurity measures and stronger regulatory compliance programs.

Extreme weather came next, which several presenters considered especially appropriate in light of the extreme cold temperatures and record snowfalls that affected much of the Southeastern U.S. the same week as the webinar. Nancy DeLeon, SERC’s senior reliability engineer for situation awareness, noted that while the cold snap was unusual, extreme weather has long been a known risk for the RE.

“We’re located in a place where we do get a lot of extreme weather — extreme colds, extreme heats, hurricanes tornadoes, a lot of thunderstorms, things like that,” DeLeon said.

The report said extreme weather can “pose significant risks to [grid] reliability” by disrupting fuel supplies and telecommunications, limiting situational awareness and causing forced outages of generation and transmission facilities. Additionally, with the grid increasingly reliant on wind and solar generation and severe weather becoming more frequent, renewable resources are uniquely vulnerable to interruption during major events.

Both top risks were labeled as “monitor” in the report, meaning that mitigation plans and guidance already exist. The third highest risk, resource uncertainty, was marked as “manage,” which means that a mitigation plan needs to be developed and implemented.

The resource uncertainty risk also stems from the accelerating shift from traditional thermal generation to renewable resources and the accompanying rise of natural gas as a supplier of reliability services such as system inertia and ramping. SERC said the change to renewables will require “continued improvements in planning approaches” to understand how the behavior of solar and wind facilities contrasts with traditional generators and account for the difference in system planning.

“Through proactive and strategic planning, and continued collaboration, the sector can sustain the reliability and resilience of the [grid] in the SERC footprint,” the report said. “SERC remains committed to driving innovation and preparedness to meet the future demands of a secure and reliable electric grid.”

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Data Centers to Drive Calif. Power Demand, Sales

CAISO peak demand will grow from 48.3 GW in 2024 to about 68 GW in 2040, according to a new forecast that attributes much of the increase to data center load.

The figure is part of the California Energy Commission’s annual update to the California Energy Demand forecast. The forecast, which is part of the Integrated Energy Policy Report (IEPR), is considered a cornerstone of the state’s energy planning process.

The commission approved the 2024 update Jan. 21.

At the same meeting, the commission welcomed its newest member: Nancy Skinner, who served in the state Senate from 2016 to 2024. Skinner replaces Commissioner Patty Monahan.

The CEC’s peak demand projections for 2040 are 66.8 GW in what’s known as the planning forecast and 68.5 GW in the local reliability forecast.

That compares to a peak demand recorded in 2023 of 44.53 GW, followed by 48.32 GW in 2024. CAISO’s all-time peak demand was 52,061 MW on Sept. 6, 2022, amid a record-breaking heat wave.

The new projections are substantially higher than those made in 2023, when estimated peak demand in 2040 was around 60 GW.

One difference is that the 2024 forecast “improved [the] characterization of the expected growth of data centers,” the CEC said in its draft IEPR update released in November.

“A significant amount of the peak growth is coming from the additional data center load that we have added this cycle,” Nick Fugate, lead forecaster in the CEC’s Energy Assessments Division, told commissioners.

Data centers typically run around the clock, including during peak hours, and therefore contribute to peak demand, Fugate said.

The CEC updated its forecasts in December after receiving new information from Pacific Gas and Electric about data center trends. The PG&E update indicated substantially more requested data center capacity compared to figures the utility submitted in September. (See CEC Ups Data Center Demand Forecast After PG&E Revisions.)

Sales Forecast

The annual peak demand growth rate in the CEC forecast through 2040 is 2.3% and 2.4% in the planning and local reliability forecasts, respectively.

The growth is even steeper for statewide electricity sales, which see a 3.2% and a 3.3% annual increase through 2040 in the planning and local reliability forecasts, respectively.

Fugate noted that peak load doesn’t grow as quickly as electricity sales in the forecast because much of the EV charging that contributes to electricity sales is expected to take place in off-peak hours.

Electricity sales will increase from about 245 TWh in 2024 to 420 TWh in 2040, under the local reliability forecast. In comparison, the CEC’s 2023 forecast predicted only about 350 TWh of electricity sales in 2040.

The CEC’s planning forecast makes “mid-range” assumptions and is used for system-level planning, such as resource adequacy.

The local reliability forecast may be used for utility distribution system planning or local area reliability studies in CAISO’s transmission planning.

Compared with the planning forecast, it assumes less behind-the-meter solar and storage, less energy efficiency and more electrification, resulting in higher predicted demand. That makes up for some of the uncertainty in forecasting for smaller areas, the CEC said.

Behind-the-meter Solar

Another change to the 2024 energy demand forecast was improved projections of behind-the-meter solar and storage. Historical data was updated based on better interconnection data from several utilities.

The CEC estimated there was 17.2 GW of behind-the-meter solar capacity in California at the end of 2023, including a record-setting 2.5 GW that was interconnected that year.

And behind-the-meter solar capacity factors were updated based on “a large real-world sample,” the CEC report said. Capacity factors are the ratio of electricity actually generated by a system to the system’s maximum capacity.

The new, lower capacity factors used in the 2024 forecast translated to lower estimates of electricity generation compared to the 2023 forecast.

On the energy storage side, the CEC found roughly 1.5 GW of behind-the-meter storage in the state through 2023, and about 84% of that was interconnected in the last five years.

In other changes made in the 2024 forecast, the CEC used the latest information about zero-emission appliance regulations to update building electrification projections. The forecast also accounted for growth in transportation electrification.

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ERCOT Technical Advisory Committee Briefs: Jan. 22, 2025

Stakeholders Sound off on Market Design Framework 

ERCOT’s Technical Advisory Committee held its first meeting of 2025 on Jan. 22, with the biggest chunk of the meeting devoted to discussing the grid operator’s proposed market design framework. 

The framework dates back to August of 2024, when ERCOT CEO Pablo Vegas presented it to the Board of Directors. It is made up of very broad guidelines to use as the grid operator develops rules and regulations, said Vice President of Commercial Operations Keith Collins. 

“What we see is that while reliability is the organization’s primary objective, cost should always be considered,” Collins said. “So, I think that hopefully will set us up for some of the discussion debate that will happen about what the meaning of this balance is.” 

ERCOT already had gotten comments from six sets of stakeholders on the document, and Collins invited them to reiterate what they wrote at the TAC meeting. 

“Our comments are meant to be very generally supportive of the framework and the intent behind the framework, because it can be helpful to have this sort of tool to help socialize and coordinate thinking about market design changes,” said Ned Bonskowski of Vistra. 

However, Vistra wanted to make sure the policy framework is not resetting all of the work the Texas legislature and Public Utility Commission have put into the markets since the February 2021 winter storm, or even further back, he added. 

The PUC shelved the performance credit mechanism in December, and ERCOT is working on implementing the real-time co-optimization (RTC) of energy and ancillary services, which means stakeholders have to look for some new policies to improve the system. 

“We want to choose among the best tools that we have available to us and use those tools efficiently,” Bonskowski said. “But we also don’t want to, for instance, give up on trying to just because we may not have the exact perfect tool that we would like to have for a situation. We should not let the perfect be the enemy of the good.” 

The Lower Colorado River Authority’s Blake Holt saw the document as providing some clarity to those who are not in the “stakeholder trenches” regularly, but he had questions on how the document would influence policy implementation at ERCOT. 

“How does ERCOT intend to resolve conflicts between competing attributes and timelines?” Holt said. “For example, [the reliability unit commitment] enhances reliability for the hours utilized. However, excessive use of the tool can lead to wear and tear on a unit and worsen reliability in the future, not to mention the out-of-market action leads to flawed and inefficient price formation.” 

One basic issue the document brought up for many is the tension between affordability and reliability, which is a universal concern in the power industry. 

“We recognize there are tradeoffs between the two, and we currently support the stance of conservative operations and understand that operating more reliability or more reliably comes with increased cost,” Holt said. “We believe the best way to support this increased cost is through markets in which these operational reserves are currently valued and reflected in as procurement.” 

Collins agreed the framework could be useful for people who are not always in stakeholder meetings to use as a way to help wade through the information that is produced at them. 

The city of Eastland’s Mark Dreyfus questioned the purpose of the document, noting that the stakeholder process implements the nitty gritty details of policy. While they are complicated, many people are involved, and ERCOT’s board has the grid operator’s entire staff to explain things to them. 

“Consumers, as a market segment, have always supported competitive markets, because we know that the competitive market — as reflected in the law, interpreted through the commission rules and into the protocols — is the best way to provide reliability at lowest cost to consumers,” Dreyfus said. 

The Texas Advanced Energy Business Alliance’s Doug Pietrucha said his group agrees that markets are the best way to ensure the right balance between reliability and affordability, but it wants to make sure that technology neutrality is a key part of market design. 

“The participation in various services should be based on the attributes that different technologies can provide, and the goal of the service shouldn’t be to be designed around the attributes of any one particular technology,” Pietrucha said. 

Mark Bruce, principal at Cratylus Advisors, questioned the value of the document, noting that policy is determined elsewhere. 

“ERCOT doesn’t get to make high-level, aspirational policy determinations and documents like this,” Bruce said. “All this talk about competitiveness, that issue has been settled since Sept. 1, 1999,” referring to the law that restructured Texas’ utility industry. 

Collins disagreed with that assessment, noting that he has worked around the country in other markets where they do not necessarily wait for FERC for directions. 

“You can blaze a path that that can help the commission determine … a reasonable approach to implementing reliability,” Collins said. “It’s one thing to say you want a reliable market. Well, how do you want a reliable market? How do you want competitive markets? And what we’re seeing here are things that help emphasize how you can achieve that.” 

Large Load Interconnection Report

In other business, TAC got an update on the number of large loads lined up to connect to the ERCOT grid. 

A combination of new standalone projects and those co-located with generation, net of a few cancellations, has ramped up the queue by 17,481 MW since TAC’s last meeting in November. With some anticipated rule changes anticipated, interconnect requests for loads energizing more than two years in the future have gone up significantly in the past two months, according to an ERCOT report. 

ERCOT has added 5,229 MW of large loads from 2022 through 2024, and that could grow to more than 80,500 MW by 2030, the report says. Projects representing more than 14,000 MW are interested in connecting to the grid this year, though most of that — and most of the 80 GW for 2030 — is under ERCOT review or has yet to submit enough information for the grid operator to even start a review. 

Votes on Leadership, Transmission, Rule Changes

The meeting opened up with TAC members voting to give Caitlin Smith of Jupiter Power another year as its chair. 

The committee elected a new vice chair, with Martha Henson of Oncor taking that role over after Collin Martin, also of Oncor, stepped down at its last meeting. (See ERCOT Technical Advisory Committee Briefs: Nov. 20, 2024.) 

TAC voted to recommend three transmission projects from Oncor that are big enough to require approval from the board: 

    • The Forney 345/138-kV Switch Rebuild Project, which costs $103.5 million, to address reliability issues in Kaufman County and will not require a certificate of convenience and necessity (CCN).
    • The Wilmer 345/138-kV Switch Project, which costs $158.2 million, to address reliability issues in Dallas, Kaufman and Ellis counties, which will require a CCN.
    • The Venus Switch to Sam Switch 345-kV Line Project, which costs $118.9 million, to address reliability issues in Ellis and Hill counties and will not require a CCN. 

In addition to the three transmission projects, TAC also voted on many rule changes, but the only one that generated debate was NPRR 1250, which is needed for ERCOT to end its renewable portfolio standard implementation practices. Others were put on a combination ballot and were approved unanimously. 

The legislature passed HB 1500 to end the renewable portfolio standard (RPS), which effectively has been moot for more than a decade, as the Texas grid has long had more renewables than was ever required by the standard. ERCOT still will run a voluntary renewable energy credit (REC) trading program but will end the mandatory REC program for RPS compliance. 

Vistra’s Bonskowski abstained from voting for NPRR 1250 because it did not eliminate several compliance provisions, but he noted they’re going to be dealt with in a future rule change. 

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ISO-NE Details Evaluation Models for Transmission Solicitation

ISO-NE has outlined the transmission and economic models it plans to use to evaluate proposals submitted for the longer-term transmission planning (LTTP) process.

The RTO is developing the first request for proposals (RFP) for the LTTP process, which is intended to address transmission needs identified in long-term planning studies. FERC approved the new process in July. (See FERC Approves New Pathway for New England Transmission Projects.)

At the direction of the New England States Committee on Electricity (NESCOE), the first LTTP solicitation focuses on increasing the transfer capability at two interfaces in Maine and facilitating the interconnection of at least 1,200 MW of onshore wind in the state. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

To help qualified transmission project sponsors (QTPS) develop their proposals, ISO-NE will publish transmission and economic models, said Dan Schwarting, manager of transmission planning at ISO-NE. The models will use the same basic structure as those used by ISO-NE to evaluate projects but will use generic information for generator performance to protect confidentiality.

The economic models outlined at the Planning Advisory Committee (PAC) meeting Jan. 23 will include a capacity expansion model and a production cost model. The capacity expansion model will determine “the amounts and types of generation needed to adequately serve load over multiple years, given emissions constraints and load growth,” Schwarting said. The production cost model will calculate hourly data on generation dispatch, power flow and production cost.

ISO-NE plans to use its version of the models to calculate benefit-to-cost ratios (BCRs) for proposals. These financial benefit calculations will account for production cost and congestion savings, avoided capital costs, avoided transmission investment, reductions of line losses and reductions of unserved energy.

For a project to be selected in the LTTP, the BCR calculation must show that its benefits outweigh its costs. If multiple projects pass this threshold, ISO-NE is not required to select the proposal with the highest BCR and also will consider factors including project scope, permitting challenges and “constructability,” Schwarting said.

If no projects pass the threshold, FERC has approved a “supplemental process” in which one or more states could opt to cover the costs that exceed the threshold.

In February, ISO-NE plans to provide additional modeling details to the PAC, including an outline of its modeling of “representative onshore wind projects in northern Maine,” and the composite load model the RTO will use for stability simulations.

Schwarting said ISO-NE plans to release a draft RFP to NESCOE and the QTPS to solicit feedback prior to publishing the official RFP in March. He said this limited review process would “strike a balance between feedback and timeliness in issuing the RFP.”

Several people asked ISO-NE to expand the opportunity to provide feedback to all stakeholders. Sheila Keane, director of analysis at NESCOE, also expressed an interest in expanding the draft RFP review process.

“As we think about this being the first time through for everyone … it seems like adding in some transparency on the draft RFP might add some value to the process without adding too much time,” Keane said.

After issuing the RFP, ISO-NE plans to give transmission developers six months to submit proposals, followed by a yearlong period for ISO-NE to evaluate and select a proposal. Under this timeline, ISO-NE would likely select a solution by September 2026.

“If it is possible to accelerate this timeline we certainly will,” Schwarting said.

2024 Economic Study

Also at the PAC meeting, ISO-NE presented the final policy scenario results of its 2024 Economic Study, which is intended to evaluate “economic and environmental impacts of New England regional policies, federal policies and various resource technologies on satisfying future resource needs in the region.”

The preliminary results of the policy scenario, presented in November, found the need to add 58 GW of capacity from a range of zero carbon resources including renewables, energy storage and small modular reactors (SMRs).

The study found that carbon constraints will drive capacity expansion from 2033 to 2039, after which both carbon constraints and load growth will drive resource additions.

Overall, the final results indicate New England will need to add a cumulative capacity of 77,176 MW by 2050. Compared to the preliminary results, the increased need for new capacity reflects a reduced SMR buildout, which increases the amount of capacity required from other resources.

As the region decarbonizes, SMRs could help fill an essential firm power role and limit the need to overbuild intermittent renewables. ISO-NE has deemed hydrogen generation, carbon capture and storage, and geothermal generation — other potential low-carbon dispatchable resources — to be infeasible solutions for the region due to geological constraints.

The model found that, in 2050, “without additional revenue incentives, SMRs only operate at a 21% capacity factor, but they successfully provide emission free dispatchable generation in the winter to reduce overall system emissions,” said Elinor Ross of ISO-NE.

The results also indicate that the cost of additional carbon reductions will increase exponentially as the power system nears full decarbonization in the leadup to 2050.

“Hours of high solar and wind generation are easy to decarbonize at a low cost,” said Ross. “The remaining hours left to be decarbonized require energy storage and SMRs, which are more expensive than wind and solar.”

Sensitivity analyses also highlighted the significant cost benefits of land-based wind, which was “consistently the most cost effective resource in a levelized cost analysis,” Ross said.

Reducing the limitations on onshore wind decreased the overall build costs in the model. In the most extreme sensitivity considered by ISO-NE — which allowed the model to build unlimited land-based wind — the model added more than 44 GW of onshore wind, cutting the overall build costs nearly in half relative to the reference case.

ISO-NE is taking feedback on the policy scenario results and requests for additional sensitivity scenarios through the end of February.

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Trump Says Data Center Power Plants Will be Expedited

President Donald Trump presented the World Economic Forum with his desire to power the U.S. AI revolution: behind-the-meter generation co-located with data centers and built rapidly under his National Energy Emergency executive order. 

This scenario could avoid the yearslong delays of siting and permitting, he said, and would bypass the transmission grid, which he said is aging and vulnerable to attack. 

Trump spoke virtually Jan. 23 to the annual gathering of global leaders and decision-makers in Davos, Switzerland. 

In response to a question from TotalEnergies CEO Patrick Pouyanne about U.S. LNG exports, Trump segued from fast-tracking LNG facilities to fast-tracking new power generation. 

“I’m going to get them the approval,” he said. “Under emergency declaration, I can get the approvals done myself without having to go through years of waiting. And the big problem is we need double the energy we currently have in the United States — can you imagine? — for AI to really be as big as we want to have it.” 

Powering major consumers through on-site generation rather than through the grid is a very old concept, but Trump claimed the idea of doing it with a data center is new. 

Trump, a vociferous critic of renewable energy, said new plants could run on whatever fuel the developers like, but he suggested “good clean coal,” if only as a backup fuel. 

Trump’s comments come as the U.S. power sector scrambles to meet what is expected to be a huge increase in power demand from reindustrialization, data center expansion and societal electrification. 

Some experts are skeptical the demand will increase as much as the largest projections indicate, but some increase appears inevitable: artificial intelligence is a heavy power draw, and Trump is pushing to make the U.S. a leader in AI. 

The newest projection of AI data center power needs was offered the same day as Trump spoke, when Goldman Sachs Research estimated the facilities’ power consumption would increase more than 160% from 2023 levels by 2030. 

There has been keen interest in powering data centers with nuclear power, thanks to its near-constant output and near-zero emissions. 

But Goldman Sachs Research concludes it would be impossible to meet the near-term needs entirely with nuclear. To do so would require 85 to 90 GW of new capacity by 2030, and only a small fraction of that amount is expected to be online by then. 

Relying instead on fossil generation would ratchet up greenhouse gas emissions, the report’s authors write. 

Instead, they suggest a mix of fossil, renewable, storage and nuclear power in the short term. 

“Our conversations with renewable developers indicate that wind and solar could serve roughly 80% of a data center’s power demand if paired with storage, but some sort of baseload generation is needed to meet the 24/7 demand,” said Jim Schneider, a digital infrastructure analyst at Goldman Sachs Research. 

The authors also note that future innovations could help reduce Big Data’s power needs — from 2015 to 2019, data center workload nearly tripled but electricity consumption was flat, due to increased energy efficiency.  

They conclude: “Since 2020, efficiency gains have decelerated, but the team expects more innovations to help lower the power intensity of data centers in future.” 

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Trump Energy, Interior Cabinet Picks Easily Pass Committee Votes

The Senate Energy and Natural Resources Committee on Jan. 23 sent the nominations of Douglas Burgum to be interior secretary and Chris Wright to be energy secretary to the floor in bipartisan votes. 

“At their nomination hearings last week, the nominees proved that they’re committed to implementing President Trump’s plan to unleash American energy by ending the policies of climate alarmism and extremism, prepared to streamline permitting and rescind regulations that impose needless burdens on energy production and consequently the American people,” ENR Chair Mike Lee, R-Utah, said at the committee’s meeting. 

Burgum cleared the committee by an 18-to-2 vote, while Wright secured a 15-to-5 vote as more Democrats voted against him. (See: Trump DOE Nominee Seeks to Assuage Senate Democrats.) 

The committee votes yesterday come just a week after Burgum testified before the committee, and eight days after Wright did. (See: Burgum Criticizes ‘FERC Queues’ for Too Many Renewables.) 

Lee said he hoped the two nominations would move quickly to a vote by the full Senate, and leadership has been pushing through Trump’s cabinet nominees, having already secured a unanimous confirmation vote for Secretary of State Marco Rubio on Jan. 20. 

Sen. Ron Wyden (D-Ore.), the ranking member on the Senate Finance Committee, explained he opposed both nominees because of Trump’s opposition to clean energy tax credits that both the Finance and ENR committees had worked. 

“Rolling back this law is unilaterally disarming America in the face of China,” Wyden said. “Because President Trump states he wants to beat the Chinese while seeming to prefer policies that undermine America’s greatest advantages, I cannot support nominees that will carry out these policies.” 

Sen. Maria Cantwell (D-Wash.) said she opposed Wright for more local concerns — cleaning up the old plutonium producing site in Hanford, Wash. Wright said cleaning up the site was a top priority, but Cantwell said his commitment to the Tri-Party Agreement that has governed the cleanup for decades was “unsatisfactory.” 

“We get roughly about $2 billion a year in the national budget to clean up Hanford, and we have every energy secretary really pushed by [the White House Office of Management and Budget] to basically try to do cleanup on the short,” Cantwell said. “So, I hope maybe between now and the floor, I might get a stronger commitment on the Tri-Party Agreement.” 

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NYISO Begins Capacity Market Structure Review

NYISO on Jan. 22 laid out the timeline for its Capacity Market Structure Review project, which will take up the better part of 2025. 

Speaking to the Installed Capacity Working Group, Brendan Long, market design specialist for NYISO, said the objectives of the review include identifying current market structures “that will help facilitate New York’s evolving grid consistent with policy goals” and exploring potential alternatives. The ISO will solicit feedback from the group throughout the year with the goal of producing a final report in the fourth quarter. 

Just like the rest of the U.S., demand for electricity is growing exponentially in New York. The review was called for by stakeholders and the ISO last year to determine whether the capacity market provides adequate resources efficiently and effectively. 

According to its schedule, NYISO will propose a priority list of key areas of the market for potential enhancement by the end of the first quarter, propose an initial set of “high-level solutions” in the second quarter and “further analyze and refine” the recommendations in the third. 

In response to stakeholder questions, Long said that considering reactive power compensation was on the table and that the review would include evaluating how the market ensures transmission security. The ISO also will consider long-duration energy storage compensation structures. 

“It’s absolutely something we’ll consider, and we’ll whittle down further as the project progresses,” Long said.  

One stakeholder pointed out the project came about because market participants were frustrated with the capacity market; they asked whether identifying the sources of frustration was a priority for the review. Long said NYISO is “definitely going to keep our ears open” for stakeholder feedback and it will play a major role in the direction of the study. 

“I think that it’s important that part of this project is an articulation of why the current structure is not working,” Chris Casey, of the Natural Resources Defense Council, said in agreement with the previous stakeholder. “I think it’s important to zoom in on that to know how to fix it. It’s more than just collecting the frustrations of the stakeholders. We need to identify and articulate the reasons why this market might not be producing efficient results anymore.” 

NYISO’s structures needed to be harmonized with the state’s programs, he said. “I don’t think we should come out of this with a structure that pretends that certain revenue sources don’t exist or is otherwise blind to state programs because I think that ultimately produces results that are inefficient and costing customers more than they need to pay.” 

Doreen Saia, chair of the Energy and Natural Resources Practice at Greenberg Traurig, echoed Casey’s point, saying any capacity market changes needed to take state policy into consideration. 

Saia also asked the ISO to keep in mind the market structure has been in place for more than a quarter-century and stakeholders would require “adequate meeting time” to discuss potential changes. This comment came after a November and December in which stakeholders had grown frustrated with ISO projects they saw as rushed or incomplete. (See Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes and Winter of NYISO Stakeholders’ Discontent over ‘Complete’ Projects.) 

Several stakeholders, including Casey, urged the ISO to avoid incrementalism and seriously consider the fundamental structure of the market. They said changes, like new types of resources, might be coming in 10 to 20 years and any new market structures had to be flexible enough to accommodate them. 

“Fundamental changes to the structure, at least looking into them, are in the scope of this project,” Long said. “It might not necessarily be prioritized in our list of key areas, but I wanted to clarify that it will definitely be something we’re open to hearing feedback.” 

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6th Circuit Rules Against Michigan Local Clearing Requirement

A federal appeals court has brought Michigan’s practice of requiring some amount of locally generated electricity to a standstill, finding that the Michigan Public Service Commission violated the Commerce Clause when designing local clearing requirements.

The 6th U.S. Circuit Court of Appeals decided in a Jan. 16 order that Michigan’s local clearing requirement — which requires load-serving entities and alternative energy suppliers alike in the lower peninsula to procure an increasing percentage of their total capacity from within MISO’s Zone 7 — is discriminatory and “impermissibly interferes with interstate commerce” (23-1280). The appeals court reversed and remanded a district court’s earlier finding that the requirement does not discriminate against interstate commerce.

MISO’s Zone 7 encompasses the lower peninsula, while the upper peninsula and a portion of Wisconsin are in Zone 2. Michigan relies on MISO’s local clearing requirements to establish its own but adds the condition that some capacity comes from in-zone sources.

Energy Michigan, comprised of a group of the state’s alternative energy suppliers and the Association of Businesses Advocating Tariff Equity (ABATE), an association of industrial and manufacturing entities that use the alternative suppliers, originally sued the Michigan Public Service Commission for its 2017 order establishing the local clearing requirements (U-18197).

“Can the State of Michigan require someone selling a product in Michigan to procure that product from the state? Or, phrased in the language of the coin’s other side, can Michigan bar in-state retailers from obtaining their merchandise from outside the state? On these issues, negative Commerce Clause jurisprudence is straightforward. Whether the product at issue is milk, or coal-based electricity, the Commerce Clause prohibits such state restrictions unless they clear strict scrutiny’s high bar,” the court said, drawing on past cases.

The court said the Michigan PSC couldn’t make a law that “overtly blocks the flow of interstate commerce at a state’s borders.”

The Michigan PSC argued that it didn’t discriminate because the order’s language doesn’t mention state boundaries, only MISO’s local resource zones. The court called that “not much of a step” because Zone 7 geographically corresponds with Michigan’s lower peninsula.

Michigan regulators also argued that the clearing requirement’s purpose is to promote resource adequacy, not to protect domestic industry. Energy Michigan and ABATE took a different view of the law, arguing that it’s meant to favor utilities in the marketplace and drive out alternative energy suppliers, which are more likely to sell out-of-state electricity. Michigan allows up to 10% of retail electricity sales to be purchased from alternative electric suppliers.

However, the court said the aim of the requirement is irrelevant.

“Even the most benign purpose … cannot save a facially discriminatory law from strict scrutiny,” it said. The court added it judged the percentage requirement the same way it would a requirement dictating 100% of peak demand be procured from Michigan “or even an entire ban on electricity supply derived outside the state’s borders.”

Finally, the Michigan PSC argued that the Federal Power Act authorized it to enact the local requirement, pointing to a section that removes facilities used for electricity generation from federal jurisdiction. The court responded that “it is difficult to see how this provision authorizes, let alone unambiguously so,” Michigan to discriminate against interstate commerce.

Circuit Judge Danny Boggs dissented from the ruling, saying the case deserves some nuance and is “clearly” beyond the scope of the Commerce Clause because of the players involved. He said the district court erred in its conclusion that public utilities and alternative electric suppliers are similarly situated entities simply because they offer the same commodity.

Boggs argued that unlike the state’s utilities, unregulated alternative electric suppliers typically contract with industrial manufacturers and mid-size commercial customers and aren’t under an obligation to serve.

“At bottom, eliminating the local clearing requirement would do nothing to further the Commerce Clause’s ‘fundamental objective of preserving a national market for competition,’ and it would undermine the reliability of the state’s grid. The majority of Michigan’s retail electricity market remains in the hands of the public utilities, who have an unshakable obligation to serve that vital market,” Boggs wrote.

Boggs said MISO’s local resource zones are not only based on state boundaries but also drawn according to results of MISO’s loss of load expectation studies, “the relative strength of transmission interconnections,” the electrical boundaries of local balancing authorities and the seams between RTOs.

“Declining to give full weight to the judgment of state and local regulators on a matter of state and local concern is a fraught exercise, particularly considering the intricate area of energy regulation at play here,” Boggs wrote. “Geographic proximity to generation improves grid reliability, and without the requirement to secure in-state capacity, Michigan would be at risk of falling short of federal reliability standards.”

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Study Models West Coast OSW Transmission Options

A new report by two national laboratories finds that offshore wind could be generating as much as 33 GW of electricity for the western United States by 2050 and looks at how best to bring that power ashore. 

The “West Coast Offshore Wind Transmission Study” also points out the region will need as much as 400 GW of new capacity by 2050, and that the floating infrastructure needed for the deep water off the West Coast presents engineering challenges. 

Another, more immediate problem is not mentioned in the report: politics. The report was published Jan. 15, just five days before President Trump slapped an executive order of indefinite duration and as-yet indeterminate impact on offshore wind development in U.S. waters. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

Teams of researchers at the Pacific Northwest National Laboratory and National Renewable Energy Laboratory spent two years preparing the study. 

They focused on a 9,265-square-mile region off northern California and southern Oregon where the wind is strongest (22 mph average), the water depth is tenable (4,265 feet maximum) and there is minimal overlap with protected zones, tribal communities and other potential conflicts. 

They studied two transmission models: 

A radial structure, where each wind farm is connected to one point on the coast, would be simpler to build but less versatile in operation, they found. 

A backbone structure, in which wind farms are connected to each other at sea as well as to points of interconnection on land, would carry a higher upfront cost but would allow cheaper energy to be moved more efficiently across regions. 

The researchers found that starting with a radial structure and expanding it into a backbone structure would present the best cost-benefit mix and result in savings that could equal $25 billion in 2024 dollars — mostly because it would allow grid regions to better share lower-cost energy such as hydropower and solar power. 

Lead author Travis Douville, PNNL’s wind systems integration portfolio manager, said such an addition of offshore wind power also would boost resilience in the coastal region, as there are not many generators along the coast. 

“With careful planning and coordination across multiple points in time, we can solve the question of how offshore wind generation and transmission could be developed on the West Coast for maximum benefit,” he said.