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April 17, 2025

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EIA Projects Demise of Coal, Rise of Renewables

The U.S. Energy Information Administration predicts sharp increases in renewable power generation and sharp decreases in coal-fired power in its 2025 Annual Energy Outlook, released April 15.

The EIA also projects an overall decrease in U.S. energy consumption over the next decade, with subsequent increases so small that 2050 levels still are lower than 2024 levels.

The agency notes that the numbers vary among the modeling scenarios used, and it makes clear the projections were created using the laws and regulations in place in December 2024 — a month before a president who supported energy conservation was replaced by one moving to increase energy production and consumption.

The EIA and its parent agency, the Department of Energy, now work for President Donald Trump. The April 15 release of the AEO was accompanied by a DOE spokesperson’s attack on President Joe Biden’s policies and affirmation of Trump’s policies.

Some of the projections in the outlook — such as a drop in nuclear generation capacity — seem to run counter to recently stated priorities. Others, such as the rise of renewables and demise of coal, reflect Biden policies that Trump is trying to reverse.

Changes in annual metrics projected from 2024 to 2050 include:

    • Net electricity available to the grid will jump from 4,139 billion kilowatt-hours (BkWh) to 6,045 BkWh.
    • Natural gas generation will drop from 1,901 BkWh to 1,270.
    • Nuclear generation will drop from 777 BkWh to 736.
    • Coal generation will drop from 660 BkWh to 7, with the biggest decrease — 402 BkWh to 52 — coming from 2029 to 2032.
    • Renewables will jump from 1,060 BkWh to 4,680.
    • Average end use electricity prices (in 2024 dollars) across all sectors will drop from 13 cents/kWh to 12.1 cents.
    • Electricity purchased for vehicle charging will jump from 0.06 quadrillion British thermal units (quads) to 2.68 quads, with residential users accounting for 59% of the total and commercial 41%.
    • Heating degree days will decrease 5.4% nationwide per year, and cooling degree days will increase 15.7%.
    • Energy consumption intensity will drop from 91,300 BTU/square foot to 84,900 in commercial settings and from 52,300 to 40,800 in residential settings.
    • Annual generation by major renewables will jump from 0.4 BkWh to 174 BkWh for offshore wind, 16 to 56 for geothermal, 201 to 1,791 for grid-connected solar, 242 to 273 for hydroelectric and 446 to 1,908 for onshore wind.

While the U.S. produced more crude oil and natural gas per year than any other country ever during the Biden administration, Biden also led policy changes that promoted renewables over fossil fuels.

Trump railed against this during his campaign and initiated a sharp change of course on the first day of his second term. His administration continued this narrative as it commented on the AEO.

DOE spokesperson Andrea Woods said the report reflects Biden’s short-sighted energy policies and the disastrous path they set for the countries. It does not, she said, reflect the policies enacted by Trump.

The department, she said, is working now to advance coal, natural gas and nuclear energy to promote affordable, reliable and secure energy and build U.S. energy dominance.

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DC Circuit Rejects Entergy Attempt to Save MISO Capacity Obligation Rule

The D.C. Circuit Court of Appeals has denied Entergy’s repeat attempt to revive a 50% minimum capacity obligation rule for MISO’s load-serving entities.

The court concluded in an April 15 decision that Entergy lacked standing to request the discarded rule be implemented (22-1334). The minimum capacity obligation would have required MISO load-serving entities to demonstrate they obtained at least 50% of the capacity required to serve peak load obligations ahead of and without the assistance of MISO’s capacity auctions.

“Even if we were to consider the standing arguments Entergy now belatedly advances, the company has not demonstrated the necessary concrete, imminent and redressable injury,” the court decided.

The case dates to MISO’s successful bid to create seasonal capacity auctions paired with availability-based resource accreditations.

FERC in 2022 allowed MISO to conduct four seasonal capacity auctions and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. However, the commission blocked MISO’s companion proposal to institute a minimum capacity obligation (ER22-496). (See FERC Again Rejects MISO Minimum Capacity Obligation.)

At the time, MISO reasoned that such a rule would keep suppliers from relying too heavily on its capacity auction to serve their customers’ needs. The RTO thought it would encourage proactive bilateral contracting and better maintain resource adequacy.

But FERC said MISO did not fully contemplate how the proposal could give its largest utilities too much market power. The commission rejected the rule a second time on rehearing requests from MISO and Entergy’s operating companies. Entergy took its challenge to the D.C. Circuit Court. (See Entergy Seeks Review of FERC’s Block on MISO Capacity Obligation.) The D.C. Circuit said Entergy’s opening brief lacked argument, analysis and evidence to support its standing in the case.

“The words ‘standing,’ ‘injury,’ ‘traceability’ and ‘redressability’ do not appear in the document,” the court noted. It said it wasn’t until a reply brief that Entergy argued its basis for standing was “apparent.” However, the court said, “no reasonable reader … would walk away with a clear understanding of petitioners’ precise injuries, the chain of causation and how a decision of this court could redress those harms.” The court said it would not “repackage merits arguments as support for a petitioner’s standing.”

Entergy argued that a refusal of the minimum capacity obligation would lead to future grid risks and free ridership by other MISO utilities on the back of Entergy’s investments. The company complained that MISO’s auction clearing prices are too low to recover its generation investments. It said requiring utilities to secure at least 50% of their needed capacity outside the auctions would mean it would be able to recoup costs through more contracts with other MISO market participants.

The court disagreed that Entergy’s standing was self-evident and said its injuries weren’t apparent or traceable. It also didn’t accept Entergy’s explanation that it omitted its reasoning for standing due to a “clerical oversight.” Judges said they saw “no basis for excusing Entergy’s noncompliance.”

The court concluded Entergy failed to submit any proof outlining how it would be harmed financially by heightened reliability risks under the status quo and, conversely, spared from them had FERC accepted the minimum capacity obligation rule. The court said even descriptions of the reliability crisis weren’t uniform in the case record, with some sections referencing an “immediate concern” while other parts called it a nonissue and said it “could result” in an “impact on reliability … over the next decade.”

Lastly, the D.C. Circuit said a complex sequence of hypothetical events must unfold before Entergy’s claims of injury from future free ridership make sense. It said other utilities would have to turn to Entergy for bilateral contracts and negotiate deals containing higher prices to compensate Entergy for its capital expenses.

“Entergy wholly fails to articulate how this chain of events would occur,” the court said, also noting that Entergy’s only evidence of more future contracts was a citation to the Independent Market Monitor’s concern that Entergy, as a pivotal MISO supplier, would be able to use a minimum capacity obligation to charge “anticompetitive” prices to other utilities.

“Implicitly, then, Entergy’s causal chain rests on an exercise of market power — a fact which Entergy repeatedly and strenuously rejects. Entergy cannot credit the market power objections for standing purposes but disavow them on the merits,” the D.C. Circuit said.

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NYISO Announces 2 New Board Members

NYISO has appointed two new members to its Board of Directors, Chair Joseph Oates announced at the board’s meeting with the Management Committee on April 15.

Heather Rivard will join the board in July following her retirement from Southern California Edison, where she has served as senior vice president of transmission and distribution since September 2021. Prior to that she worked for DTE Energy for 28 years, climbing the ladder there until she was senior vice president of electric distribution.

Steve Doyon, who joined the board effective that day, was most recently the president and CEO of Onward Energy, an independent power producer in Denver that operates and manages over 6 GW of wind, solar and gas generation. He has worked in the energy industry for nearly 40 years at several companies, including DTE, Cogentrix Energy, AES and Terra-Gen Power.

“The board is very excited to have the two of them joining us,” Oates said. “And we look forward to engaging with them on the evolving energy issues we face here in New York.”

Oates and Director Gizman Abbas were reelected to the board, while Director David Hill was elected vice chair. Director Mark Lynch will chair the board’s Audit and Compliance Committee for another year, while Director Michael Crowe was assigned the chair of the Commerce and Compensation Committee. Abbas was made chair of the MC’s Liaison Subcommittee. Sally Talberg will chair the Reliability and Markets Committee.

Oates also briefly acknowledged that FERC had approved the ISO’s proposal for collecting import duties on electricity, if the Trump administration determines the president’s tariffs on Canada apply to it. (See FERC Authorizes NYISO, ISO-NE to Collect Tariffs on Electricity.)

A stakeholder asked the ISO whether there was any financial impact from the tariff levied by Ontario on its electricity exports for the short period it was in place and whether it factored into FERC’s ruling. Oates said he could not say.

“We sort of just found out this morning that FERC approved our tariff filing,” Oates said. “We’ll take that back and at the next appropriate working group or committee of the ISO, we’ll report back.”

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Federal Briefs

Report: Clean Energy Powered 40% of Global Electricity in 2024

The world used clean power sources to meet more than 40% of its electricity demand last year for the first time since the 1940s, according to a report by thinktank Ember. The report found that solar farms have been the world’s fastest-growing source of energy for the last 20 consecutive years. Overall, solar power made up almost 7% of the world’s electricity, while wind power made up just over 8%. Hydropower accounted for 14%. 

The report, which accounted for 93% of the global electricity market across 88 countries, also found that a surge in demand pushed emissions from the global power sector up by 1.6% to an all-time high last year. 

More: The Guardian 

NRC Renews Duke Energy’s Oconee Nuclear Station

The U.S. Nuclear Regulatory Commission last week renewed the operating licenses for Duke Energy’s Oconee Nuclear Station for an additional 20 years through 2054. 

Oconee is the first of Duke’s nuclear facilities to reach the milestone of extending its license and receiving approval to operate for 80 years. 

More: Greenville Business Magazine 

Senators Introduce TVA Salary Transparency Bill

U.S. Sens. Marsha Blackburn and Bill Hagerty have introduced a bill in the Senate that would require the Tennessee Valley Authority to make more salaries available to the public. The bill would require TVA to report salaries of employees making more than $123,041 per year. Currently, TVA reports only the salaries of its five highest-paid executives. The utility had 11,312 employees last year, according to its latest annual financial report, and reported the median total compensation for all employees was $163,779. 

More: Knoxville News Sentinel 

TVA Names New Government Relations Chief

The Tennessee Valley Authority has named Justin Maierhofer as its new senior vice president and chief of government relations. Maierhofer previously was a north region executive overseeing engagement of partners in Middle Tennessee and Kentucky. 

More: Knoxville News Sentinel 

BLM Approves Nevada Gas Pipeline

The Bureau of Land Management has approved a new gas pipeline in Humboldt County, Nev. An environmental analysis of the Pinyon Pipeline found no significant impact to burying the line between the existing Ruby Pipeline and the Valmy Power Plant. The pipeline will be 16 miles long and support the conversion of the North Valmy Generating Station from a coal-fired plant to a natural gas-fired plant. 

More: KOLO 

Sources: More than 2,600 DOE Staffers Accept 2nd Offer to Resign

More than 2,600 DOE staffers have opted to take the Trump administration’s second round of resignation offers, two sources said. The number is more than double the 1,217 staffers who took the first round offered in January, according to a document. It could go significantly higher in coming weeks as staffers over 40 years of age get an additional 45-day period to consider the offer. 

More: Reuters 

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Company Briefs

Occidental Petroleum Awarded Permit for Direct Carbon Capture Project

EPA has approved Occidental Petroleum’s application to capture carbon dioxide from the atmosphere and inject it underground. Occidental, a Houston-based oil firm, will start storing 500,000 metric tons of carbon dioxide in deep, non-permeable rock formations 4,400 feet underground as soon as this year. The facility will be located 20 miles southwest of Odessa. 

More: Texas Tribune 

Chevron Ordered to Pay More than $740M to Restore Louisiana Coast

Oil company Chevron must pay $744.6 million to restore damage it caused to southeast Louisiana’s coastal wetlands, a jury ruled following a trial more than a decade in the making. 

Jurors found that Texaco, acquired by Chevron in 2001, had violated Louisiana regulations governing coastal resources for decades by failing to restore wetlands impacted by dredging canals, drilling wells and billions of gallons of wastewater dumped into the marsh. The jury awarded $575 million to compensate for land loss, $161 million for contamination and $8.6 million for abandoned equipment. 

The case was the first of dozens of pending lawsuits to reach trial in Louisiana against the leading oil companies for their role in accelerating land loss along the state’s rapidly disappearing coast. The verdict, which Chevron said it will appeal, could set a precedent leaving other oil and gas firms on the hook for billions of dollars in damages tied to land loss and environmental degradation. 

More: The Associated Press 

EVelution Energy to Break Ground on Cobalt Processing Facility

EVelution Energy  said it plans to begin construction of its cobalt processing facility in Arizona later this year. It would be the only cobalt processing facility in the U.S. Cobalt is a mineral in high demand for its use in EV batteries, aerospace products and defense technologies.  

More: Arizona Republic 

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State Briefs

ARKANSAS 

Senate Passes Bill to Regulate Wind Power

The state Senate voted 29-1 to pass a bill to establish a new regulatory framework for future wind energy projects. The law would give county and city governments the ability to regulate new wind projects while also establishing minimum standards for the construction of turbines. It would require the Public Service Commission to develop rules regulating and permitting future projects, including standards for decommissioning projects, studies for impacts on wildlife and potential public safety issues, among many other provisions. The bill now heads to a committee of the House of Representatives. 

More: Arkansas Times 

COLORADO 

Montezuma County Enacts 6-month Solar Moratorium

The Montezuma County Board of County Commissioners has agreed to place a six-month moratorium on large scale solar developments. Commissioner Jim Candeleria said the board was considering the moratorium “just to pause, to make sure we have better language in land use code.” As it stands, there’s “nothing specific” to solar in the county code, said Planning and Zoning Director Don Haley. The moratorium will not bar existing applications from moving forward. 

More: The Journal 

CONNECTICUT 

House Approves 2 PURA Commissioners

The state House voted to advance two of Gov. Ned Lamont’s nominees to serve on the Public Utilities Regulatory Authority. Marissa Gillett, the chair of the PURA, cleared the chamber on a vote of 91-52, while David Arconti received a 136-9 vote. Both nominations now head to the Senate. 

More: CT Mirror 

MAINE 

Bill Removing Referendum Requirement for Nuclear Plants Fails in House

An effort aimed at removing obstacles for the development of nuclear power failed an early test in the state House of Representatives. The measure would overturn a 40-year-old requirement that proposed nuclear power projects be subject to a statewide referendum. Lawmakers adopted the requirement in 1983 as a response to public concerns about nuclear power following the partial meltdown of the Three Mile Island power plant in 1979. The bill failed an initial vote along party lines in the House. It now moves to the Senate. 

More: Maine Public Radio 

PUC to Investigate Versant Power

Following issues uncovered in an independent audit of Versant Power, the Public Utilities Commission launched a formal investigation focused on the utility’s management practices and oversight by its Canadian parent company ENMAX. 

The PUC said the audit, which was conducted in 2024, looked at the company’s operations, management structure, customer service and collections practices and the reliability of its distribution system. PUC Chair Philip Bartlett said the report “raised a number of questions regarding the judgment of Versant’s management.” Versant Power is the state’s second-largest investor-owned utility. 

More: Mainebiz 

MINNESOTA 

PUC Approves Minnesota Energy Connection Tx Line

The state Public Utilities Commission has approved Xcel Energy’s Minnesota Energy Connection Project. The project includes the construction of a 345-kV, double-circuit, high-voltage transmission line, about 174 miles in length across several counties. It also will involve modifications to existing substations. 

More: West Central Tribune 

MISSOURI 

Gov. Kehoe Signs ‘Construction in Progress’ Bill

Gov. Mike Kehoe has signed a bill into law that will allow utilities to charge customers for power plants as they are being built, rather than after they are complete. The law also requires utilities to replace retiring power plants with a similarly sized energy source that can be turned on immediately. It also includes changes to protect consumers by expanding the window of time when utilities cannot disconnect service. 

More: KCUR 

NEW MEXICO

Gov. Lujan Grisham Signs Electric Grid, Solar Power Bills into Law

Gov. Michelle Lujan Grisham signed two bills into law that will affect the state’s power industry. House Bill 128 establishes a $20 million fund to provide grants for solar energy and battery storage for tribal, rural and low-income schools, municipalities and counties. House Bill 93 allows larger utilities to incorporate advanced grid technology projects into their modernization plans and incorporate those plans into the ratemaking process before the Public Regulation Commission. 

More: Source NM 

NORTH DAKOTA

Bill Giving PSC More Tx Line Authority Heads to Governor

The state Senate approved a bill that would allow the Public Service Commission to override local government zoning authority on transmission lines. The bill gives the PSC the ability to determine if a local ordinance is unreasonable, including setback rules. The Senate Energy and Natural Resources Committee voted 4-3 to give the bill a do-not-pass recommendation after it had passed the House. It now goes to Gov. Kelly Armstrong. 

More: North Dakota Monitor 

WISCONSIN 

Utilities Apply for Rate Hikes in 2026, 2027

Xcel Energy, Alliant Energy and Madison Gas and Electric have filed applications with the Public Service Commission seeking rate hikes in 2026 and 2027. 

The utilities say they need to increase rates to upgrade aging infrastructure and to pay to build additional resources for generation. In addition, the utilities also asked the commission to approve a slight increase to their return on equity. The PSC is expected to vote on the proposals in late 2025. 

More: Wisconsin Public Radio 

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Md. Consumer Advocate Seeks Price Cut in PJM 2024 Capacity Auction

The Maryland Office of People’s Counsel has filed a complaint against PJM alleging the rules used in the 2025/26 Base Residual Auction would require consumers to pay twice for capacity provided by generators operating on reliability-must-run agreements.

The auction conducted in July 2024 resulted in a nearly 10-fold increase in capacity prices. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“PJM ran a flawed auction resulting in prices that — unless corrected — will cost Maryland residential electric customers hundreds of dollars per year in unreasonable and unnecessary capacity costs,” People’s Counsel David Lapp said in an announcement of the complaint April 14. “We are asking FERC to undo those unjust results and direct PJM to reset the prices for the 2024 auction by correcting the same flawed rules that FERC has already accepted the need to fix for future auctions.”

Pointing to a Synapse Energy Economics report commissioned by the OPC, the complaint said excluding RMR units from the supply stack would inflate costs by more than $5 billion. That report found that the 2025/26 BRA design would increase monthly costs by as much as 24% for some Maryland ratepayers. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

OPC also contends the auction allowed market manipulation, improperly exempted 1,600 MW of generation from being required to submit offers and produced prices incapable of incentivizing new entry because of the confluence of long development timelines and a compressed auction schedule. It notes the auction was conducted within a year of the start of the corresponding delivery year on June 1.

“The [FERC] and the courts have made clear that high prices are unjust and unreasonable if they do not reflect market fundamentals or cannot induce a market response. The 2025/2026 BRA results fall short on both grounds,” the complaint says.

The complaint argues that revising the auction results would not violate the filed rate doctrine as they are “intended to govern future performance” that has yet to begin. It pointed to a 2021 remand from the D.C. Circuit Court of Appeals directing FERC to reopen an investigation into MISO’s 2015/16 capacity auction, which set a $150/MW-day clearing price in its Zone 4. (See FERC to Take 2nd Look at 2015 MISO Capacity Auction.)

The complaint effectively would expedite implementation of a change the commission approved in February, granting a PJM request to model the output of RMR units as capacity as long as the resources could meet certain criteria, including being available to RTO dispatchers when called upon.

The proposal is set to go into effect for the 2026/27 and 2027/28 delivery years, with PJM intending to develop a long-term solution with stakeholders. Comments on the docket centered around two Talen Energy resources: the 1,289-MW Brandon Shores coal-fired generator and 843-MW H.A. Wagner oil-fired plant. Both facilities are located near Baltimore and are slated to deactivate after operating on RMR agreements through Dec. 31, 2028 (ER25-682, ER24-1787, ER24-1790). (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

“The 2024 auction results ignore the significant ratepayer-funded reliability contributions of the Brandon Shores and Wagner plants — with devastating consequences to customers from the resulting extraordinarily higher capacity market costs,” Lapp said. “The Federal Power Act prohibits requiring captive utility customers to pay twice for the same service.”

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GCPA Conference Examines the Biggest Change to ERCOT Market in 15 Years

HOUSTON — ERCOT this December will begin implementing a market design change that has been debated for more than a decade, experts said at the Gulf Coast Power Association’s Annual Spring Conference on April 14.

The real-time co-optimization (RTC) of energy and ancillary services means that ERCOT’s security-constrained economic dispatch will solve for both at the same time. Vice President of Commercial Operations Keith Collins said it could save billions of dollars a year in operating the grid, with a study finding RTC plus batteries (RTC+B) could save between $2.5 billion and $6.4 billion annually.

“Ultimately, there’s a lot of benefit this is going to derive to the market, to the ratepayers and consumers,” Collins said. “And you see that this is something that, while it’s been in the works for a long time, we are essentially at the dawn of the RTC location.”

The big difference in the potential benefits has to do with the years the market change was “back cast” for testing, which included the summer of 2023, when conditions in ERCOT were tight and prices were high, Collins said.

R Street Senior Fellow Beth Garza was a big supporter of the move when she was ERCOT’s Independent Market Monitor, saying she got the grid operator and the Texas Public Utility Commission on board with the market change in 2018. The biggest change since that time has been the growth of storage, with 11 GW now competing in the markets.

“This idea of ‘RTC plus B,’ in my mind, has become ‘RTC because of B,’” Garza said. “For storage to be able to easily move into and out of providing energy versus capacity for ancillary services needed something different. And here it is.”

The change will save money by dispatching a plant that had reserved some capacity for ancillary services in the energy market and then shifting the ancillary service to a more expensive plant, lowering the overall cost of power, according to ERCOT.

“We are getting more expensive ancillary services,” ERCOT Principal of Market Design and Development Dave Maggio said. “So that can be a question of, is that necessarily a good thing? And the answer in this case is, yes, it is worth getting more expensive ancillary services because of the overall decreasing energy price.”

The change also comes with a new offer cap in the energy markets, at just $2,000/MWh, down from the current $5,000/MWh. Prices can still go above $2,000/MWh, but as in the FERC-regulated markets, that will only happen when the market is running short. Scarcity pricing will be handled through the “ancillary services demand curve,” which will replace the operating reserves demand curve (ORDC), Maggio said.

While RTC is set to go live Dec. 5, ERCOT is going to be spending the next seven months getting ready for it with market trials starting May 5, and a market notice explaining them is due soon, said Matt Mereness, the grid operator’s senior director of market operations and implementation.

The training will involve weekly calls with market participants and, starting in September, trial runs of the new market design that will cover the morning ramps, Mereness said. ERCOT ran similar tests 15 years ago when it transitioned to a nodal design from zonal.

“Who was here for the nodal go-live 15 years ago?” Mereness asked the audience. “Now raise your hand if you did that. Well, the good news is it’s not that big, but this is still the biggest paradigm shift we’ve had in 15 years.”

The move to RTC is going to mean more efficient energy and ancillary services markets, which means that to drive more resource investments, the market will need to have more scarcity events that drive prices high and send price signals for investments, said NRG Senior Director of Regulatory Affairs Bill Barnes.

“We are becoming more dependent on the demand curve for price elevation,” Barnes said. “I think that’s a good thing. … When we first started, there wasn’t an ORDC. We were solely dependent on submitting high offers. As we’ve evolved over the past 20 years, we’ve moved more towards a demand curve approach, which to me more aligns the price formation with the actual fundamentals of the market, versus one participant deciding to submit the price of the cap on a random day, which can be not a good thing.”

While the move to RTC+B will influence price formation in ERCOT’s markets, consultant Eric Goff said generation investments in the near future are going to be driven by large loads like data centers coming to Texas.

“The reason, among others, that large loads are attracted here is because you can transact in this market,” Goff said. “You can get what you want without having to ask for too much permission, and if those large loads contribute to higher prices because of their demand, which they have been, in the long run, then you get to a price that reflects the cost of entry.”

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FERC Authorizes NYISO, ISO-NE to Collect Tariffs on Electricity

FERC on April 14 approved filings by NYISO and ISO-NE authorizing them to collect tariffs on electricity imports from Canada, if the “relevant federal authorities” deem them responsible for doing so (ER25-1462, ER25-1445).

The grid operators have said President Donald Trump’s tariffs on energy imports do not appear to apply to electricity. However, to prevent potential financial consequences, both saw the need to establish a framework for collecting them.

The commission accepted both grid operators’ proposed open access transmission tariff revisions for allocating Trump’s tariffs. NYISO proposed to charge the “financially responsible party,” while ISO-NE proposed to charge “the entities selling the assessed electricity into the ISO-administered market.” (See ISO-NE Braces for Tariffs on Canadian Electricity and NYISO Preparing to Collect Duties on Canadian Electricity Imports.)

Both grid operators wrote that their cost collection methods would allow importers to include the costs of the duties in market offers. The mechanisms could change if the federal government gives clear instructions to them to collect the tariffs differently. ISO-NE included in its proposal a provision allowing it to collect the duties “in accordance with any federal regulations or guidance,” while FERC directed NYISO to add a similar provision in an additional filing.

FERC emphasized that it makes “no finding regarding whether import duties imposed pursuant to the Canadian tariff executive order apply to Canadian electricity or whether [the grid operators are] required to pay them,” and similarly declined to rule on whether it is legal to apply the import duties to electricity.

Because of the “exigent circumstances present,” FERC directed both grid operators to file “any legal and/or technical guidance and related documentation from the relevant federal authorities showing that a federal agency has assessed an import duty on Canadian electricity imports” that triggers the grid operator’s collection authority, “as soon as practicable after receiving such invoice.”

If they do start collecting the tariffs, the grid operators must provide informational filings to FERC every six months for three years about the costs of the duties.

ISO-NE’s proposal is intended to be a temporary mechanism; if the RTO anticipates tariffs lasting longer than 120 days, it must file a permanent cost collection method within 120 days of the first import duty invoice.

ISO-NE responded: “We still believe the tariffs do not apply to electricity, and that if they do, ISO-NE would not be the entity responsible for implementing them. There is a lot of uncertainty around the situation, and the proposal is a proactive move covering one possible outcome.” They also published a press release, saying ” the ISO is committed to maintaining ongoing dialogue with our stakeholders, state officials, and the federal government.”

NYISO said it had no further comments.

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Report Estimates Billions in Savings from More Interregional Transmission

The authors of a new report released April 4 say better market integration and reduced interregional constraints in the U.S. transmission network would have saved as much as $12 billion in 2022 and 2023.

They note the importance of achieving better grid integration in an era when increasing amounts of renewable generation is coming online but flag the difficulty of achieving it, given the financial incentive existing generators have to delay or block such integration.

The working paper, “Power Flows, Part 2: Transmission Lowers US Generation Costs, But Generator Incentives Are Not Aligned,” was written by Dasom Ham, Owen Kay and Catherine Hausman as part of Resources for the Future’s Obstacles to Energy Infrastructure research project.

They write that geographic constraints and mismatched supply and demand are growing as intermittent wind and solar capacity come online, often far removed from high-demand areas.

Better integration of electricity markets could allow systemwide cost savings and therefore lower consumer costs, the paper says. Integration of existing supply across regions could have saved $5.8 billion to $7.1 billion under 2022 conditions (which included higher natural gas prices) and $3.4 billion to $5 billion under 2023 conditions.

Other savings that could be created by intraregional integration were not estimated, nor does the report offer a full cost-benefit analysis of building new transmission or look at the cost versus societal benefit of building renewables.

But such integration would also create winners and losers, as existing generators in high-demand markets see their net profits drop and renewables in high-supply markets avoid curtailment.

The structure and processes of markets give those incumbents many opportunities to delay or block transmission construction projects that would run counter to their interests, and the report highlights case studies in multiple regions where they appear to have done just that.

This opposition can be hidden within workings of RTOs or it can be publicly visible, such as NextEra Energy’s long-running but unsuccessful fight to thwart Avangrid’s construction of the New England Clean Energy Connect, which will bring up to 1.2 GW of cheap Canadian hydropower to a region where NextEra operates multiple power plants.

The analysis showed these dynamics vary substantially by region: Greater market integration would benefit existing power producers in the Great Lakes, Great Plains and Rocky Mountain regions but hurt producers in the Northeast and Southeast.

The barriers to siting, planning, permitting and construction of transmission are well known, and include cost allocation, land rights and environmental clearance. Importantly, transmission planning and changes to market structure for interregional electricity trade depends largely on the consensus of incumbent generation companies, who hold greater sway than stakeholders who would see cost savings.

Investment patterns in recent years show the result of these dynamics: Only 2% of new circuit miles installed from 2011 to 2020 were for interregional transmission lines, and the majority of all transmission investments were for local reliability concerns rather than generation cost savings.

The new report builds on “Power Flows: Transmission Lines, Allocative Efficiency and Corporate Profits,” a working paper written by Hausman and issued by the National Bureau of Economic Research in January 2024.

The earlier report focused on the MISO and SPP regions, but the new report looks at the entire continental U.S. The dynamics are similar and can be generalized, but MISO and SPP do have some distinctive features, and there were some limitations in extending the research design to the rest of the country.

Data was obtained primarily from the Energy Information Administration and EPA’s Continuous Emissions Monitors Systems datasets.