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March 23, 2025

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FERC Approves Tariff for SPP RTO West

FERC has accepted SPP’s proposed revisions to its tariff that will incorporate seven Western Interconnection entities as transmission-owning members of the RTO, making the grid operator the first to provide full market services in the grid’s two major interconnections.

The commission on March 20 directed SPP to make a compliance filing within 30 days. It also required the RTO to provide a notification of the RTO West’s go-live date no later than six months prior (ER24-2184).

SPP has targeted April 2026 as when the entities will begin participating in its Integrated Marketplace, transmission planning, reliability coordination and other RTO services. They all are members of the Western Energy Imbalance Service market, which SPP has administered since 2021:

    • Basin Electric Power Cooperative
    • Colorado Springs Utilities
    • Deseret Power Electric Cooperative
    • Municipal Energy Agency of Nebraska
    • Platte River Power Authority
    • Tri-State Generation and Transmission Association
    • Western Area Power Administration’s Colorado River Storage Project, Rocky Mountain and Upper Great Plains regions

FERC agreed with the grid operator that its proposal to integrate the expansion members into its RTO likely will improve grid reliability and operational efficiency, benefiting existing members and new ones. SPP has said RTO West will provide more than $200 million in annual benefits to its members, primarily through the optimization of DC ties with the Eastern Interconnection. (See SPP Files to Incorporate Western Entities into RTO.)

“The RTO West proposal will consolidate the management of transmission facilities under a single, centrally cleared market and allow SPP to dispatch resources more efficiently across a broader geographic area,” FERC said.

“Expanding the RTO into the Western Interconnection is an exciting step in SPP’s growth, bringing value to new and existing members while enhancing reliability in both interconnections,” CEO Barbara Sugg said in a news release.

The commission filed a deficiency letter in October after SPP’s first tariff filing and asked for further clarifications on six issues, including the optimization of DC ties. (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.)

It said the RTO’s proposed DC tie access and incremental market efficiency use charges are reasonable given the “unique role that the West DC ties will play” in connecting SPP’s Western and Eastern balancing area authorities and the increased costs that will result from the ties’ use in market dispatch.

“Absent these charges, these increased costs would be borne fully by customers in the West DC ties’ transmission pricing zones because the [annual transmission revenue requirement] for each West DC tie will continue to be recovered from its respective transmission owner’s zone,” the commissioners wrote.

SPP said it is working with additional Western utilities that have expressed interest in becoming RTO members once this initial expansion is complete.

The grid operator is developing a second Western market in Markets+, a day-ahead offering centered primarily on the Pacific Northwest that secured FERC approval in January. It also serves as the program administrator for the Western Power Pool’s Western Resource Adequacy Program. (See SPP Markets+ Tariff Wins FERC Approval.)

“Multiple markets maximize value for all participants,” Sugg said.

The grid operator has expanded its footprint in the Eastern Interconnection from eight to 14 states since it became an RTO in 2004. The Western expansion will increase its service territory to all or part of 17 states.

The RTO’s expansion is part of the grid operator’s five-year strategic plan, Aspire 2026.

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ACP: Storage Set Installation Record for 2024

The storage industry set a record of 12.3 GW in installations in 2024, according to the U.S. Energy Storage Monitor report that was written for the American Clean Power Association by Wood Mackenzie.

Developers installed a total of 12,314 MW, or 37,143 MWh, increases of 33% and 34%, respectively, over 2023.

“After another year of record deployment, energy storage is solidifying its place as a leading solution for strengthening American energy security and grid reliability in a time of historic rising demand for electricity,” ACP Vice President of Energy Storage Noah Roberts said in a statement. “The energy storage industry has quickly scaled to meet the moment and deliver reliability and cost savings for American communities, serving a critical role firming and balancing low-cost renewables and enhancing the efficiency of thermal power plants.”

Texas and California led the way with installations, representing 61% of the total with the other 39% being spread across 13 states. Most of the installations in the fourth quarter were utility-scale, with Texas seeing 1,185 MW installed, California 857 MW, New Mexico 400 MW, Oregon 292 MW, Arizona 185 MW and North Carolina 115 MW.

Overall, fourth-quarter installations were down 20% from the fourth quarter of 2023, which the report said was caused by the delay of 2 GW of projects in late-stage development that should be installed this year.

Distributed storage saw high levels of installation as well, with 1,250 MW installed for the residential sector — a new record. Residential installations set a fourth-quarter record as well at 380 MW, a 6% increase over the previous quarter. Installers across the country are working to install more storage at consumer homes, with Arizona seeing a spike in activity as more firms sought to combine solar with storage.

Storage for the community-scale, commercial and industrial (CCI) sectors was up 22% on the year to hit 145 MW in 2024, with California, Massachusetts and New York accounting for 88% of that capacity.

The report forecasts 13.3 GW, or 43.2 GWh, of installations this year, a 22% increase from 2024, with the forecast going up by 11% from the last quarterly report because of the 2 GW of delays.

“Over the next five years, utility-scale installs will total 68.2 GW/256 GWh, a very similar total buildout to last quarter,” the report said. “This sustained outlook is due to political uncertainty impacting the midterm forecast being offset by storage’s role in meeting unprecedented load growth.”

Residential storage is expected to grow by 47% this year and 223% by 2029. The national attachment rate (linking solar with storage) is expected to flatten in 2025 and 2026 and then drop in future years. Attachment rates are expected to rise in every state, but solar will grow in net metering states like Florida faster than in high-attachment states like California and Puerto Rico.

CCI storage is a high-cost business, where sales and development can be more challenging than other market segments. State policy could create significant upside to the sectors by 2030s, but that is too far out to influence the forecast.

The report includes several sensitivity cases for the next five years, with a high growth one adding 10 GW over that period, which would require federal tax incentives to stay in place, avoiding additional tariffs under President Donald Trump, renewables firmed with storage deployed to meet load growth, and barriers to finance and interconnection eased.

The low case would cut installations by 22% over the rest of the decade, which assumes no more tax credits, higher tariffs on Chinese batteries, an expanded supply chain for natural gas generation and favorable treatment for it in queues, while financing and interconnection issues for storage are not addressed.

“It’s still too early to determine the final form of IRA tax incentives over the coming year,” Wood Mackenzie Global Head of Storage Allison Weis said in a statement. “The combination of new tariffs on China and other countries with continued [Section] 45X and domestic content bonus adder incentives would make U.S.-based systems more competitively priced. However, many domestic providers are not set up to meet quick demand. If higher pricing is combined with ITC tax incentives phasing out beginning in 2028, it could lower our five-year deployment outlook by as much as 19%.”

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Fate of Wind Tower Manufacturing Site in Albany Uncertain

At last year’s Alliance for Clean Energy New York conference, the Port of Albany hosted a tour of its new Beacon Island facility, which was slated to develop into a wind tower manufacturing facility. The facility could produce up to 150 towers per year and support 3,178 jobs, according to the Center for Economic Growth.

But when the port announced getting $18.8 million in funding from New York in February to install a substation, sanitary wastewater plant and fire protection system, there was no mention of the wind tower site.

“This is great news and will provide a critical boost enabling additional maritime commerce,” port CEO Richard Hendrick said in a statement. “The port will be able to move forward with the electrification infrastructure, including critical long-lead items needed in expanding the port for manufacturing opportunities.”

New York Gov. Kathy Hochul’s statement on the award referenced that the site was a “unique asset to manufacturers of a variety of large-scale components” but made no mention of building towers for offshore wind.

Penny Vavura, spokesperson for the Port of Albany, told NetZero Insider that under the current administration, the port was open to other industries on the site.

“We’re still talking to Marmen,” Vavura said, referring to the developer of the proposed site. “But if things don’t come together, we’ll still look for something that offers similar community benefits as far as employment opportunities.”

The Trump administration chilled the market for offshore wind with a first-day executive order ordering a halt to new offshore wind permitting and a review of existing leases. (See Trump Executive Orders Put 43 GW of Wind Projects at Risk.) EPA also recently pulled the permit for the Atlantic Shores project off New Jersey. (See EPA Puts Hold on Atlantic Shores OSW Permit.) Many projects have been put on pause, and industry-wide layoffs have occurred. (See OSW Critics Petition US Supreme Court for Vineyard Wind 1 Review.)

Vavura said she had “no clue” what industry, other than offshore wind, might be interested in the site.

“It’s a challenging thing to try to forecast,” Vavura said. “The next best step is to start having conversations to see what’s out there.”

A spokesperson for Marmen confirmed it was still in discussions with the port about developing the site but otherwise declined to comment. The company’s website features an Albany office “coming soon” among its divisions.

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NERC: Cold Weather Standards Now Expected in April

NERC’s Board of Trustees expects to submit the ERO’s latest cold weather standard to FERC by April 7, several days after the March 27 deadline the commission set for the standard in 2024, staff said at the monthly meeting of NERC’s Standards Committee on March 19. 

Director of Standards Development Jamie Calderon told attendees the board plans an open meeting April 4 to discuss the standard and that the ERO already has informed FERC the filing would come after the deadline. 

The standard has had an unusual path to passage, with the board ordering the SC in January to take over writing it after it failed to garner enough favorable votes from industry stakeholders to pass. Trustees exercised their authority under Section 321 of the ERO’s Rules of Procedure to sidestep the normal stakeholder approval process because they were concerned about missing FERC’s deadline. 

A team of volunteers completed work on EOP-012-3 (Extreme cold weather preparedness and operations) in January, and the SC posted it for a 45-day formal comment period that began Jan. 27 and ended March 12. (See NERC Cold Weather Standard Commenters Say More Work Needed.) Calderon said the delayed submission date was necessary because a “number of comments came in at the last minute” and the team needed more time to review them all. The SC plans to submit any relevant comments to the board along with the standard at its open meeting next month. 

Asked by Barry Lawson of Georgia Transmission whether NERC might consider pursuing “informal” extensions or arrangements with FERC in similar situations in the future, Calderon emphasized that the ERO took this route because of the “exigent circumstances” arising from the exercise of the Section 321 authority. 

“This is not the preferred operation,” Calderon said. “We do intend to file in the future, on time, every time. This was a truncated project with nine months [to finish], and the teams worked diligently over the winter holidays as well. We’re considering this to be extraordinary circumstances, due to the comments, that we will just be filing after that deadline. So it is not an extension or any agreement.” 

Trustee Sue Kelly, the board’s liaison to the SC, said that as a board member, she decided to support the delayed filing after thinking “really long and very hard.” Despite the FERC deadline, Kelly said adhering to the original date would not have provided enough time to “give full faith and credit to the last round of comments.” Chief Engineer Mark Lauby agreed that “there were some very good [comments] in there [that] helped a great deal.” 

Review of Section 321 Planned

With Section 321 now having been invoked twice by the board in the past year, the SC has begun work on a guidance document to formalize its approach the next time the board uses its special authority. 

“None of us wants [Section 321] to come up again, but in the instance that it does, we just want to make sure we can walk through the process in a really efficient manner,” said Vice Chair Troy Brumfield of American Transmission Co., who has been organizing the effort. 

Brumfield said a group of volunteers from the SC will examine both uses of Section 321. The board first invoked the rule in August 2024 to meet a FERC-imposed deadline for standards regarding inverter-based resource performance. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) 

That decision involved Section 321.2-321.4, which called for a technical conference to resolve issues with the standard and a final ballot round with 60% stakeholder approval needed for passage. The board used a different part of Section 321 for the cold weather standard, dispensing with a conference and ballot altogether and putting authority in the SC to revise the standard. 

Calderon suggested that drawing on the SC’s experience could help prevent future delays like the one that affected EOP-012-3. 

“This was the first instance we issued 321.5,” the section used for the cold weather standard, Calderon said. “There’s going to be ample discussion on ensuring that that process is allotting sufficient time, should that be taken in the future.” 

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NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept

The NYISO Business Issues Committee has approved, in concept, implementation of the ISO’s new firm fuel election process and requirements as part of its changes to capacity accreditation. 

The March 18 vote passed unanimously, with only the Market Monitoring Unit and Natural Resources Defense Council abstaining. The Installed Capacity Working Group will vote on revised tariff language before the Management Committee’s March 26 meeting. The ISO aims for a FERC filing in mid-April. 

For several weeks and across multiple working group meetings, NYISO stakeholders have been hammering out the details of the ISO’s firm fuel accreditation improvement project. The project aims to ensure generators that say they have guaranteed (firm) sources of fuel deliver on their promises during winter months. 

The ISO and the New York State Reliability Council are concerned about future fuel supply constraints in the winter. As New York transitions to a winter-peaking system, the downstate gas turbine fleet will find itself competing with home heating for fuel during peak periods. 

FERC accepted NYISO’s capacity accreditation changes in July 2024, but it delayed implementation until 2026 after generators complained of the limited amount of time to make their firm fuel elections: The changes required them to tell the ISO by Aug. 1 prior to each capability year how much of their capacity was covered by firm fuel supply. (See FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay.) 

Other requirements include that resources with firm fuel have supply, transportation and replenishment strategies in place by Dec. 1 of the capability year through the end of winter, and have fuel available to run 56 hours over any consecutive seven-day period in December through February. 

Firm suppliers would not have to submit additional attestation that they have secured fuel, and those downstate and in Long Island would get their own capacity accreditation factor. Failure to meet firm fuel performance obligations by being unavailable because of fuel supply issues on the day-ahead or real-time markets could result in audit and financial sanction. The MMU also may examine suppliers if it identifies concerns with bidding or operational behavior. 

Generators would be sanctioned based on the reason that the firm supply was unavailable, with a 1.5 multiplier added to violators who otherwise could have prevented it; NYISO would use NERC’s guidance for “outside management control” events for the base “1.0” sanction. 

During the ICAP Working Group’s meeting the day before the BIC’s vote, stakeholders wondered whether firm generators could be subject to sanctions if they were told by the ISO they were not being scheduled on the day-ahead market, sold their fuel and then were called on as part of the supplemental resource evaluation program but were unable to respond.  

Responding to this concern during the BIC meeting, Zack Smith, senior manager of capacity and new resource integration for NYISO, clarified that gas-only firm units called in for SREs that don’t respond would be evaluated only to see if fuel was available or if they made efforts to procure fuel.  

“If there was no fuel available and they made those efforts to try and find it, they will not be subject to any penalty for the firm fuel,” Smith said. “If our investigation finds that the fuel was procurable at a price and the entity did not try to get it, they will be subject to the 1.5 penalty.” 

Other stakeholders brought up the 16-month period between the firm fuel election (Aug. 1 prior to the capability year) and the deadline for having supply arrangements in place (Dec. 1 of the capability year). They argued this could lead to situations where a generator elects as firm but its fuel supplier “goes bankrupt” or experiences some other disruption and no longer can meet a firm fuel obligation. Stakeholders asked whether the eventual tariff revisions would include making generators tell the ISO if this occurred by the Dec. 1 deadline. 

Nikolai Tubbs, a market design specialist for NYISO, said the ISO was going include that provision in the procedures manual, not the tariff. 

Doreen Saia, chair of Greenburg Traurig’s energy and natural resources practice, asked whether every financial penalty should be called a sanction. She said the effect of the 1.0 modifier was to put the generator in the position of not having the financial benefit of being a firm supplier, which wasn’t really a sanction.  

“That’s not a sanction to me; that’s an adjustment,” Saia said. “I think we have to step back from calling it a sanction because [issues outside of a generator’s control are treated] no different than the EFORd [equivalent forced outage rate on demand] rules we have today. I don’t get an EFORd hit if the transmission line to my facility goes down.” 

Saia said she agreed with penalizing poor performers but that clarifying the punitive sanction from the non-punitive was necessary so future tariff revisions would be legible. “I guarantee you, six months from now when someone else is looking at this who has not been part of these conversations, they’re not going to get it.” 

Smith said NYISO still was considering whether to use the word “adjustment” or something else. He said the ISO understood her concern and was working on it. 

Market Monitor Proposes Future Firm Fuel Election Changes

Dovetailing off the firm fuel discussion at the ICAP Working Group meeting, MMU Potomac Economics proposed changes it said would better coordinate the capacity market with firm fuel elections. 

The Monitor argued there were several issues with the current structure of firm fuel elections and how they interact with the Installed Reserve Margin study and fuel constraints. At the heart of its concerns is that generators make firm fuel elections roughly 15 months before the winter performance period they are electing for and that these elections cannot be changed. This pushes into a system where the IRM, capacity accreditation factors (CAFs) and unforced capacity prices are interrelated.  

“What we are saying is that there’s a lack of market responsiveness,” Potomac’s Joe Coscia said. “We’re setting the same price regardless of whether there’s more or less fuel relative to the IRM requirement.” 

Coscia said the current system caused problems whether or not firm fuel elections were used in future IRM studies. If they were, generators could over-elect and incur financial losses or under-elect and artificially boost prices. This could increase the volatility of prices and CAFs. If they weren’t used in the IRM, then the market and IRM might not be reflective of actual fuel arrangements.  

“The resource adequacy modeling component should consider how to coordinate these fuel elections in a way that makes sense,” Coscia said. “If you meet the requirements, consumers benefit from it.” 

Potomac proposed moving the firm election deadline to after the final CAFs are published and setting the winter UCAP requirements to satisfy the reliability criteria of the IRM study. This would mean that generators’ firm fuel elections affect the amount of UCAP supplied relative to the reliability requirements, and they would be closer to when generators are sure of having contracts in place, knowing the price of fuel and the price of CAFs. 

The Monitor said that while these changes will not be in place for the 2026/27 capability year, NYISO should discuss implementing them in the long term. 

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ISO-NE Scales Back Vehicle, Heating Electrification Forecasts

As part of a major overhaul of its annual load forecasting process, ISO-NE has significantly scaled back its electrification forecast for electric vehicles and heat pumps.

Prior forecasts relied heavily on state EV targets to estimate load growth due to a lack of data on EV adoption. ISO-NE has compiled data over the past few years, enabling it to better estimate the actual adoption rates in the region, said Victoria Rojo, supervisor of load forecasting and system planning at ISO-NE.

“Comprehensive vehicle registration data has indicated that prior forecasts have exceeded actual EV registrations,” Rojo told the Planning Advisory Committee on March 19.

ISO-NE has indicated its 2024 Capacity, Energy, Loads and Transmission (CELT) report overestimated the adoption of personal light-duty vehicles by more than 70%. As a result, the RTO is reducing its adoption forecasts for all classes of electric vehicles.

To a lesser extent, the RTO also has reined in its forecast for heat pump adoption in the region, reducing its 2025 adoption expectation for Connecticut by 30% and for Massachusetts by 15%. The changes aim to account for “state policies, goals and [the] best available historical installation data.”

While ISO-NE still expects heating and transportation electrification to increase substantially long-term, the updated adoption numbers significantly decrease the energy forecast for the upcoming decade. In its draft CELT forecast, ISO-NE reduced its annual net energy projection for 2033 by 8.2%, from 140,001 GWh to 128,460 GWh.

The RTO also cut its summer peak load projection for 2033 to 26,663 MW, a 1.4% reduction, and dropped its winter peak projection to 24,440 MW, an 8.7% reduction.

This is the second straight year ISO-NE has scaled back its demand forecasts. In 2024 it reduced its 10-year summer peak load forecast by 1.8% and its winter peak by 2.5%. (See ISO-NE Decreases Its 10-year Peak Load Forecast.)

An ISO-NE study looking at 2032 — which relied on the elevated 2023 CELT forecast — found limited risk of shortfall on the New England grid, with the greatest risks coming during extreme winter weather scenarios. (See ISO-NE Sees Little Shortfall Risk for 2032.)

The electrification adoption changes are one component of a revamped forecasting methodology ISO-NE has rolled out for its 2025 CELT report. The new modeling capabilities will enable the RTO to estimate hourly power demand in each load zone more than 20 years into the future. The modeling will rely on zonal, county-level forecasts of electric vehicles, heat pumps and behind-the-meter solar.

“Each forecast component (base load, EV, HP and BTM PV) reflects coincident weather over a 70-year simulation period and are combined into forecasts of net and gross load for each zone and the region,” Rojo noted.

The new methodology also introduces “climate-adjusted weather data reflecting 70 weather years,” Rojo said. ISO-NE previously had not included the effects of climate change in its CELT forecasts.

The modeling also uses energy efficiency as an input to the model, eliminating the need for a separate energy efficiency forecast.

The RTO plans to publish its final CELT forecast in May.

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PUC Adds 2 More Projects to Texas Energy Fund

The Texas Public Utility Commission has advanced two generation projects for due diligence review as part of the Texas Energy Fund’s In-ERCOT loan program, filling a hole left by two proposals that dropped out earlier this year.

The PUC accepted staff’s recommendation during its open meeting March 13 to add NRG Energy and Vistra projects to the TEF portfolio. The companies are seeking $548 million in TEF funds for their 895 MW of potential new generation (56896).

NRG plans to add a 455-MW, quick-start natural gas peaker at its Greens Bayou facility outside Houston. Vistra has proposed a second Permian Power 440-MW natural gas peaker in the Permian Basin. Permian Power I, one of the first projects selected, would be built next to Vistra’s existing 325-MW gas unit near Monahans in West Texas.

PUC attorney Laurie Hobbs said staff prioritized applicants that meet the commission’s priorities, including speed to market, ability to relieve transmission constraints and diversity of dispatchable resource types.

“We’re really trying to still balance as many of the [commission’s] original policy priorities … but we must present you with applicants that can begin timely construction of their projects,” she told the commissioners.

ENGIE Flexible Generation NA withdrew a 930-MW peaking facility from consideration in February, and Howard Energy Partners pulled back a co-generation facility in January. Both companies said supply chain issues would delay the projects and keep them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)

“We need to make sure as best as we can that any project we approve going forward can meet these deadlines and be online,” PUC Chair Thomas Gleeson said.

The In-ERCOT portfolio has 19 applications, totaling 9,774 MW of new gas generation, for $5.37 billion in loaned TEF funds.

Deputy Executive Director Barksdale English told the commission that Vistra generator Luminant, NRG, Constellation Energy and Calpine account for 35% of the TEF projects. He said adding more participants would increase competition.

Constellation said in January it plans to acquire Calpine, the nation’s largest operator of geothermal and natural gas power generation. (See Constellation to Acquire Calpine for $29.1B.)

The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.

The fund is composed of four programs: In-ERCOT Generation Loans; In-ERCOT Completion Bonus Grants; Outside-ERCOT Grants; and Texas Backup Power Package.

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Maryland Crossover Day Update: Bills Passed, Amended, Waiting

The Utility Transparency and Accountability Act was one of the dozens of bills the Maryland House of Delegates passed March 17, sending it to the Senate as part of the legislature’s “crossover day,” which begins a three-week countdown to the close of the 2025 session on April 7. 

Otherwise known as HB 121, the bill would require the state’s electric utilities to file a yearly report on all their votes at PJM, or any other RTO, including votes taken at “any committee, user group, task force or other part of the regional transmission organization in which votes are taken.”  

Votes are to be reported whether or not they are final votes or made by a person with decision-making authority, the bill says. HB 121 passed the House 128-8, while the Senate version, SB 37, passed with 45-0, on Feb. 27. 

With energy a top priority for the Assembly’s Democratic leadership, the bills that crossed over, and the amendments needed for passage, were significant. 

For example, SB 116 originally called for the state’s Department of the Environment and Energy Administration to work with the University of Maryland School of Business to produce a report analyzing the environmental, economic and energy impacts of data center development in the state. 

But to gain Republican support — and a 46-0 vote — the language requiring the report to look at the energy impacts of data centers was stripped out of the bill. 

The House version, HB 270, crossed over Feb. 17 on a 125-8 vote, with no amendments, which means final passage could depend on either the House accepting the Senate amendment or the Senate backtracking.  

Amendments could take the teeth out of another bill, SB 149, and its House version, HB 128, a Democratic-sponsored proposal to create a Climate Change Adaptation and Mitigation Program that would require fossil fuel producers doing business in the state to pay fees that would be used to mitigate the impacts of climate change in Maryland.  

A flurry of amendments on March 14 essentially rewrote the Senate version, which now would only require the state’s comptroller and Environment and Commerce departments “to conduct a study to assess the total cost of greenhouse gas emissions in the state.” The same amendments were adopted in the House, and both bills passed March 17. 

Hoping to Cross Over

Not all state legislatures have crossover days, but among those that do, failure to pass one house by the specified date typically means a bill essentially is dead for the session. In Maryland, however, bills that do not cross over still can move forward with a special vote in the rules committee of either house. 

Leaders in both houses appear to be relying on that strategy for the passage of three major energy bills, often referred to as “the leadership package.” The bills cover a range of issues critical for the state to meet its growing energy demand while ensuring affordability and reliability and cutting dependence on imported power, primarily from PJM. (See Ahead of Crossover Day, Energy Bills Stalled in Md. General Assembly.) 

    • The Energy Resource Adequacy and Planning Act (SB 909) would require the Maryland Public Service Commission to establish an Integrated Resource Planning Office, which would conduct a 25-year comprehensive energy forecast aimed at meeting state clean energy and emission reduction goals. 
    • The Renewable Energy Certainty Act (SB 931) would set rigorous standards for solar and storage projects seeking a certificate of public necessity and convenience from the PSC, to ensure careful siting and community engagement. The bill also would prohibit city or county governments from passing zoning or other laws blocking solar and storage projects. 
    • The Next Generation Energy Act (SB 937) would promote the development of nuclear energy, and the extension of the licenses of existing reactors, as a matter of state policy, while also encouraging regional collaboration between states to share costs on the development of new reactors. The bill also calls for the procurement of 3,100 MW of “dispatchable energy generation capacity” and a temporary expedited permitting process for these projects.  

None of the bills crossed over on March 17, but energy advocates and lawmakers like Del. Lorig Charkoudian (D) have said negotiations over possible amendments are ongoing. Speaking with NetZero Insider on March 13, Charkoudian said, “I think what you’re going to see, when they kind of come out or start going through the process in committee, is just a lot of amendments to add, to improve, take the best ideas and move them on.” 

She is sponsoring another bill, the Abundant, Affordable Clean Energy (AACE) Act (HB 398, SB 316) which calls for major new procurements of energy storage and solar in the state, as well as better transmission planning for offshore wind and license extensions for existing nuclear plants. Charkoudian said she is working on proposing some of the bill’s provisions as amendments to SB 937. 

Distribution and Transmission Planning

Katie Mettle, policy principal for Maryland at Advanced Energy United, is promoting another non-crossover, SB 908 and HB 1225, which would require the state’s utilities to submit detailed distribution system plans to the PSC every three years. The bill calls for these plans to include demand-side management options such as virtual power plants, as well as non-wires solutions for improving reliability.  

Mettle remains “cautiously optimistic” it still could move forward. “We love it because it has the potential to save rate payers a lot of money on their electricity delivery costs over time,” she said. “Just building out infrastructure in the most cost-effective way possible … will also lower demand on the grid and really make the grid a lot more reliable.” 

Other bills crossing over included: 

    • HB 155, which would allow the state’s Community Development Administration to provide loans for energy efficiency and clean energy upgrades for multifamily, low- and moderate-income buildings. The loans could be 0% interest, with deferred repayment plans lasting 15 to 40 years. The Senate version, SB 247, still is in committee. 
    • HB 49, which provides exclusions to the state’s building performance standards in special cases, such as not counting emissions related to the production of steam used for sterilizing medical instruments or from backup generation at a health care facility. The bill also gives building owners the option of paying a compliance fee if they cannot meet the state’s performance standards. 
    • HB 829, another Charkoudian bill, would require transmission developers seeking approval for a new line to provide the PSC with evidence they had considered alternatives, such as grid-enhancing technologies or distribution system upgrades that would defer the need for a new line. The bill does not have a Senate version.  
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ACEEE State Efficiency Scorecard Gives California Top Marks

California earned the top score in the American Council for an Energy Efficient Economy’s 2025 State Energy Efficiency Scorecard, released March 18. 

The scorecard showed state spending on efficiency rebounded last year to set a record of $8.8 billion, with 90% of the increase coming from five states: Massachusetts, Missouri, New Jersey, New York and Pennsylvania. California scored 93.5 out of 100 points in ACEEE’s rankings, followed by Massachusetts at 80.5 and New York at 79.5, with Maryland and Vermont tied for fourth place at 77. 

“Leading states are reducing costs and cutting pollution through energy savings measures, but many other states are stagnating,” Mark Kresowik, ACEEE senior policy director and lead author of the scorecard, said in a statement. “American families have endured years of rising costs and need relief. Energy efficiency upgrades lower utility bills, and now is the time for state policymakers and regulators to help more families see those savings.” 

Louisiana was the most improved state, jumping nine places to No. 37 after it adopted a strong building code, which was primarily motivated by skyrocketing insurance costs for homes due to extreme weather, ACEEE said. 

Wyoming was at the bottom of the list at just 5.5 points, with Alabama (6 points) and Mississippi (6.5 points) coming in just ahead of it. 

Colorado reached the top 10 for the first time, jumping six spots to reach No. 7 after it adopted policies for clean vehicles and a new efficiency standard to cut energy consumption in large buildings and enacted a range of efficiency standards. 

“The top states are consistently advancing efficiency across every category, typically receiving at least half of the available points in each sector,” the report said. “The second tier is making considerable progress, but more inconsistently across sectors.” 

ACEEE has been releasing the scorecard for 16 years, and it sees a new focus on efficiency due to rising energy bills, with a bigger focus on helping low-income consumers. Efficiency programs invested more than $2 billion last year to make efficiency upgrades that cut their monthly bills, but more than 75% of that was from just four states: California, Massachusetts, Michigan and New York. 

“In the wake of rapidly rising energy prices and electricity bills, several states are recognizing energy efficiency’s important role in keeping energy affordable by helping homeowners and businesses reduce costs, by improving living conditions, and by creating jobs, all while supporting increasingly ambitious state and local goals to reduce carbon emissions,” the report said. 

States are ranked in six primary policy areas: utility and public benefits programs, transportation policies, building efficiency policies, state government-led policies, industrial energy efficiency and appliance and equipment standards. 

Points used to be allocated solely to policies that saved the most energy, but since 2022, the scorecard has started including carbon benefits, which means that policies such as vehicle electrification and building decarbonization generate more points.

States can get 100 points, with 29 from utility programs, 26 from transportation programs, 24 relating to building efficiency policies, nine points to state-led initiatives, six points for industrial programs and six points for state appliance and equipment standards. 

Most states have room for improvement on the building energy code because only six have adopted the latest model. Nine states have no code at all, though among them, Colorado requires localities to adopt building codes. 

The codes apply to new buildings and can require existing buildings to save energy. Four states and the District of Columbia have adopted standards requiring large buildings to cut energy consumption and climate pollution over time. 

A dozen states have adopted clean vehicle standards first developed by California, requiring automakers to sell more zero-emissions cars. An additional 15 states have signed deals to start moving medium- and heavy-duty vehicles to zero-emissions. 

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DC Circuit Reverses Course on Vacating FERC Approvals of 2 LNG Sites

The D.C. Circuit Court of Appeals on March 18 reversed its vacatur of FERC’s approvals of two LNG export facilities in Texas, having been convinced on appeal that the commission’s procedural errors were not as serious as it initially judged.

The court had vacated FERC’s 2019 approvals of the Brownsville Shipping Channel and Rio Grande LNG in Cameron County, Texas, and remanded them for additional proceedings in 2024. (See DC Circuit Vacates FERC Approval of Two LNG Facilities in Texas.) The court’s vacatur, along with another decision, led then-Chair Willie Phillips to consider changes to how FERC was reviewing natural gas infrastructure. (See DC Circuit Orders Could Lead FERC to Rethink its Natural Gas Policies.)

The three-judge panel’s initial decision held that while the vacatur might cause significant disruptions to the projects, that did not outweigh the seriousness of the commission’s procedural defects in the case. Among them was that, having its approvals already remanded in 2021, FERC did not conduct new environmental impact statements for the projects.

The court followed a precedent that vacatur is warranted when an agency commits a “fundamental” procedural error, such as skipping an environmental review altogether.

“The procedural steps the commission skipped here were important, but they were not ‘fundamental’ in the same sense,” the same panel said. “The commission has already issued extensive final environmental impact statements reflecting more than three years of review and public comment.”

While the decision reversed the vacaturs, FERC must undertake some additional environmental reviews of specific subjects, like Rio Grande’s proposal to add carbon capture and storage to its facility.

“Against that backdrop, the seriousness of the reauthorization orders’ deficiencies does not outweigh the disruptive effects of vacatur,” the court said. “This court never doubted that vacatur would impose significant disruptive consequences … and respondent-intervenors have provided more details about those consequences in their rehearing petitions.”

The complex, large-scale projects have been in development for more than eight years. The court agreed that vacatur would upend their construction schedules, prevent developers from meeting contractual obligations, and stall their ability to get financing and finalize labor contracts — impacting thousands of jobs.

President Donald Trump’s executive orders on energy also have changed some of the legal questions, but the court declined to resolve new issues they brought up because doing so would not have changed its decision that vacatur was not warranted, it said.