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June 29, 2024

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Texas PUC Adds OPUC’s Hjaltman as 5th Commissioner

Texas’ Public Utility Commission is back to its full five-commissioner complement with the appointment of Courtney Hjaltman, CEO of the Office of Public Utility Counsel (OPUC) since 2022. 

Texas Gov. Greg Abbott named Hjaltman to the PUC on June 24 for a term that expires Sept. 1, 2025. She fills the seat left vacant by Will McAdams, who stepped down from the PUC in December to focus on his family and health. 

Abbott said Hjaltman’s service to the state and her legal expertise makes her the “ideal choice” to serve on the commission. “Courtney will ensure that Texans in every corner of our state have access to quality utility services for years to come,” he said in a statement. 

As OPUC’s CEO, Hjaltman advocated for Texas’ residential and small commercial customers. During the ERCOT Board of Directors’ meetings June 17-18, she voted against a protocol change revising an ERCOT ancillary service over concerns it would raise consumers’ rates. That likely means she will have to recuse herself when the PUC considers the protocol change. 

Hjaltman was Abbott’s deputy legislative director when she was appointed to OPUC and has more than 17 years of state service, much of it in the legislature. She holds bachelor’s degrees in science and arts from The University of Texas and is a graduate of the governor’s Executive Development Program at UT’s Lyndon B. Johnson School of Public Affairs. 

State lawmakers increased the size of the PUC from three commissioners to five after the disastrous and deadly 2021 winter storm. The three incumbents at the time lost their jobs in the storm’s aftermath.  

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Report: Industrial Electrification Should Focus on ‘Easy to Abate’ Sectors

The U.S. could ramp up the electrification of heavy industry by 50%, reduce the sector’s fossil fuel use by 25% and cut its greenhouse gas emissions by 100 million metric tons per year by 2030, according to a new report from Schneider Electric’s Sustainability Research Institute.

But hitting those ambitious targets will require a shift of focus, the report says. Instead of prioritizing long-term solutions for the hardest-to-abate industries, such as petrochemicals, oil and coal, a different approach could zero in on the lower-hanging fruit of individual processes that can be electrified with existing technologies and without major changes to production.

“Emissions are not all equal,” the report says. “Those that can be reduced more rapidly hold much greater value than those that could be reduced in the future (even if massive).”

Pushing toward President Joe Biden’s goal of reducing the nation’s GHG emissions by 50 to 52% from 2005 levels by 2030, the U.S. has focused on electrification of transportation and buildings via incentives in the Inflation Reduction Act. But industrial electrification varies from sector to sector, the report says.

Electric arc furnaces are widely used in steel production, but options for electrifying the high-temperature process heat needed for chemicals and oil and gas refining still are in the demonstration phase, according to the Department of Energy’s recent Pathways to Commercial Liftoff: Industrial Decarbonization report.

Industry accounts for about 23% of U.S. greenhouse gas emissions, according to EPA. The Schneider report notes that five sectors ― chemicals, petroleum and coal products, primary metals, nonmetallic minerals and paper ― make up close to 75% of that total.

Traditional approaches to industrial decarbonization require that certain hard-to-abate industries continue to rely on natural gas or other fossil fuels to produce the high heat they need, until alternative technologies such as green hydrogen, carbon capture and sequestration, and small modular reactors can be commercialized at scale.

The report cites 2020 research from the California Energy Commission suggesting that building electrification could drive a switch away from natural gas and a decrease in the customer base, driving up natural gas prices for buildings and industry. Natural gas prices for industry could double by 2030, the CEC report predicts.

“This is particularly relevant in the context of rapid relocalization of a number of industries in the country,” the Schneider report says. “Will these new facilities be built for a net-zero world, relying on alternative and sustainable energy resources, or will they be connected to the existing natural gas grid and perpetuate reliance on fossil fuels?”

To move toward electrification, the report breaks down industrial energy use and emissions into subprocesses ― direct and indirect, process and nonprocess ― and identifies which could be electrified quickly in the coming decade. For example, most nonprocess energy use ― that is, energy not used for manufacturing but for building operations such as lighting and space heating and cooling ― could be rapidly electrified with existing technologies.

A second phase of industrial electrification would include the technologies currently being demonstrated but not yet deployed at commercial scale, especially for targeted processes in sectors such as food and beverage, textiles and electrical equipment, the report says.

Of the 21 industrial sectors analyzed in the report, the combination of the first and second phases could push eight to 80% electrification and 16 to at least 60% within a decade.

The report notes that half the reductions in fossil fuel use and GHG emissions will come from “easy to abate” industrial sectors, rather than hard-to-abate processes.

The report acknowledges the reduction in fossil fuel use will increase electricity demand ― by about 300 TWh per year ― but assumes that this new demand would be met with the wind, solar and storage sitting in interconnection queues across the country, providing additional efficiencies and emission reductions.

Getting the Finances Right

Beyond 2030, a third phase of industrial electrification would require innovative technologies still in development, such as electric “cracking” furnaces used in the production of petrochemicals and other electric furnaces, the report says.

Such innovations could drive industrial electrification to 64% across sectors, with 14 sectors hitting 80%, the report says.

“This major opportunity challenges the current hard-to-abate-centric approach to industrial decarbonization, which suggests little is achievable until new innovations deploy at scale.”

The obstacles ahead include a lack of information about the potential benefits of industrial electrification, getting the finances right and “grid reinforcements, which take several years to materialize.” The report provides general, mostly familiar recommendations.

To raise public and industry awareness, the report proposes the launch of dedicated state offices or clearinghouses to advance industrial electrification.

Getting the finances right will require making the cost of electrification competitive or at least comparable with natural gas, through tax incentives but also new approaches to electricity rate-setting, including time-of-use rates, to promote system flexibility.

Grid modernization and expansion will take time and will “come at the expense of natural gas grids and their associated revenues,” the report says. “This also requires a specific policy focus to ensure a smooth transition.”

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Federal Briefs

EPA, DOE Announce $850M to Reduce Methane from Oil, Gas Sector

EPA and the Department of Energy last week announced that applications are open for $850 million in funding for projects that will help monitor, measure, quantify and reduce methane emissions from the oil and natural gas sector. 

Oil and gas facilities are the nation’s largest industrial source of methane, a climate “super pollutant” that is responsible for about one-third of the warming from greenhouse gases occurring today. 

The funds are from the Inflation Reduction Act. Applicants are required to submit community benefits plans to demonstrate meaningful engagement with and tangible benefits to the communities in which the proposed projects will be located. 

More: EPA 

DOE Picks New Company for Hanford Site Work

The Department of Energy has picked a California company for a contract worth up to $8.3 million to administer worker’s compensation claims at the Hanford nuclear site in Eastern Washington. 

Innovative Claim Solutions will replace Penser North America, of Lacey, Wash., which has held contracts to do that work since 2009. The new contract has a one-year base period, followed by options for one-year extensions up to a total of five years. 

The Penser contract, valued at $4.6 million when it was awarded, expires Sept. 30. A 60-day transition to Innovative will begin on Aug. 1. 

More: Tri-City Herald 

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State Briefs

CONNECTICUT 

Moody’s Downgrades Eversource’s CL&P to Negative Outlook

Moody’s Ratings last week downgraded Eversource Energy’s Connecticut Light and Power subsidiary to a negative outlook based largely on “an inconsistent and unpredictable regulatory environment.” 

The downgrade reinforces longstanding complaints by Eversource and United Illuminating, also recently downgraded, that their ability to raise capital is suffering from what they call “arbitrary” regulatory decisions that undercut their ability to earn on the hundreds of millions of dollars that they invest annually in clean energy projects and other grid improvements. 

“CL&P’s electric distribution business operates under the purview of the [Public Utilities Regulatory Authority], a regulatory framework that has become increasingly difficult due to higher political scrutiny and inconsistent regulatory decisions and rate case outcomes,” Moody’s said. 

More: Hartford Courant 

LOUISIANA 

Craig Greene Won’t Seek Re-election to PSC

Public Service Commissioner Craig Greene last week announced he will not seek re-election once his term concludes at the end of the year. 

“When you know, you know,” Greene, first elected in 2017, said in a news release. “For almost a decade, I’ve worked hard to keep a watchful eye on our utility providers, holding them accountable to keep prices affordable for the many families in our community struggling to get by.” 

Greene, who works full time as an orthopedic surgeon in Baton Rouge, said he will spend the extra time enjoying activities with his family and caring for his patients. 

More: Louisiana Illuminator 

MISSISSIPPI 

Hinds County Approves Apex Solar Farm

The Hinds County Board of Supervisors last week voted 3-2 to approve the 396-MW Soul City Solar farm. The 6,000-acre project, developed by Apex Clean Energy, will be the largest in the state when completed. Construction is planned to start this year and be completed by 2027. 

More: The Clarion-Ledger 

NEBRASKA 

Oldest Operating Wind Turbines in State to be Removed

Lincoln Electric System will remove two 290-foot-tall turbines, installed in 1998 and 1999, in July, as they have reached the end of their productivity. 

They were the oldest continuously operating wind turbines in the state, producing 1.3 MW combined. Both could have lasted a little longer, LES said, but it estimates it will save $100,000 by taking them down now. 

Scott Benson, manager of resource and transmission planning at LES, said the turbines helped the utility learn enough about wind power to enter its first small contracts for wind farms. “We learned a lot from them.” 

More: Nebraska Examiner 

NEW YORK

National Grid Says More Staff Needed to Comply with Climate Law

National Grid last week asked the Public Service Commission to raise annual electric delivery rates by $525 million a year across its upstate territory. If approved, the rate hike would raise the average monthly electric bill by $18.92 (15%). 

National Grid said one of the reasons for its request is the state’s 2019 Climate Leadership and Community Protection Act, as it is putting new pressures on the company to hire more employees to comply with the law. 

“The company is seeking to add incremental [full-time employees] to support its customer programs,” National Grid said in its filing with the PSC. “From a broad perspective [this] is necessitated primarily by the need to achieve the [law’s] energy efficiency and emissions-reduction goals.” 

More: Times Union 

NYSEG Fined $11.4M for Poor Customer Service Performance

New York State Electric and Gas was fined $11.4 million by the Public Service Commission for failing to meet all four of its customer service performance metrics. NYSEG’s sister company, Rochester Gas & Electric, also failed to meet all four metrics, resulting in a $7.1 million penalty. 

“Ensuring that the utilities operation in New York state maintain good customer service is a top priority for the commission,” said Chair Rory Christian. 

More: WETM 

Old Gas Line Left Open Caused Blast that Destroyed Syracuse Home

An explosion that collapsed a Syracuse house and injured 13 people last week was caused by an open natural gas line, fire officials said. 

Fire investigators inspecting the basement noticed a gas line intended to feed a clothes dryer was not connected to an appliance. The gas line had an open valve and was free-flowing natural gas at the time of the explosion. 

The landlord said there hadn’t been a dryer hooked up to the gas line for years. The line was not capped and had a shutoff valve that was found in the open position. The line should have been capped, officials said. 

More: Syracuse.com 

OHIO 

Texts Show DeWine Initiated Dark Money Payment, Sparks New Bill

Newly revealed texts show that despite claiming no knowledge of the extent of FirstEnergy’s dark money support for his gubernatorial races, Gov. Mike DeWine (R) personally solicited money from CEO Charles Jones. 

About a month before the 2018 election that launched DeWine into the governor’s office, he sent a text to Jones — indicted earlier this year on bribery charges — looking for cash. Jones forwarded the text to Senior Vice President Mike Dowling, who also was indicted this year on bribery charges. A $500,000 “dark money” contribution was later made. DeWine has not been accused of any criminal wrongdoing. 

The news has prompted Republican lawmakers to draft legislation requiring greater campaign finance disclosure from dark money groups. 

More: Cleveland.com; Ohio Capital Journal 

RHODE ISLAND

McKee Signs Legislation to Regulate Solar Companies

Gov. Dan McKee last week signed legislation designed to regulate solar companies and protect consumers from deceptive sales practices. 

The act will require solar retailers to register their business and a roster of their representatives soliciting sales. Retailers also must conduct criminal background checks on principal officers and sales representatives, as well as follow municipal restrictions on door-to-door sales and federal telemarketing rules. 

The law will take effect March 1, 2025. 

More: WPRI 

VERMONT 

Legislature Overrides Scott, Passes Renewables Bill

The state legislature last week overturned Gov. Phil Scott’s (R) veto and enacted a law that requires utilities to source all of their electricity from renewable resources by 2035. 

Scott had said the bill would be too costly for ratepayers. Under the legislation, the biggest utilities will need to meet the goal by 2030. 

Senate President Pro Tempore Philip Baruth (D) called the governor’s veto an attempt to continue rejecting “critical progress on climate action” at a time when residents are still facing “the impacts of recent climate disasters.” 

More: The Associated Press 

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Company Briefs

ClearVue PV Selects San Jose for HQ

Solar developer ClearVue PV last week announced it has selected San Jose, Calif., for its U.S. headquarters. 

Australia-based ClearVue has developed specialized glass technologies that can keep a window fully transparent and generate electricity. The window allows light to pass through the glass before redirecting the incoming sun rays onto cells that can generate electricity for a building. 

The company expects to expand to 20 workers in San Jose. 

More: Redlands Daily Facts 

Ineos, NextEra Break Ground on Texas Solar Project

Chemicals company Ineos Olefins & Polymers USA, along with NextEra Energy Resources, announced they have begun construction of a 310-MW solar project in Bosque County, Texas. 

A NextEra subsidiary will build, own and operate the INEOS Hickerson Solar farm. The companies hope to reach commercial operation by December 2025. 

More: Renewables Now 

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FERC Preparing Multiple NERC Decisions

ERO Enterprise stakeholders will be closely watching FERC’s open meeting this week for updates on several items related to NERC and its reliability standards. 

NERC’s proposed cold weather standard EOP-012-2 (Extreme cold weather preparedness and operations) is among the topics the commission might be deciding at its meeting (RD24-5). The ERO submitted the standard for approval in February after NERC’s Board of Trustees approved it. 

FERC ordered NERC to develop the new standard last year to replace EOP-012-1, which the commission approved last year while noting numerous “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods” that must be addressed before EOP-012-1 takes effect this October. (See FERC Orders New Reliability Standards in Response to Uri.)  

The replacement standard has met some criticism from stakeholders: This year, the ISO/RTO Council (IRC) expressed “united opposition” to EOP-012-2 and called on FERC to remand the standard back to NERC for revision. In its comment, the IRC said NERC’s proposed requirements were “subjective [and] unclear,” for example by excusing generator owners from implementing freeze protection measures by claiming a “cold weather constraint,” or by granting overly generous exemptions for existing generating units.  

NERC dismissed IRC’s objections in an April filing, indicating that its drafting team had aimed to “provide a high bar for generators that operate in cold weather” while addressing concerns that overly stringent requirements could push generator operators to not use their facilities in cold weather at all.  

Assessment Proposal Still Under Consideration

Also on FERC’s agenda is the commission’s proposal to require NERC to submit performance assessments every three years, shortening the timeline from the five-year cycle currently in effect (RM21-12).  

FERC suggested the shortened time frame in 2021, saying a quicker turnaround would “provide better continuity” in the commission’s oversight of the ERO Enterprise and its ability to identify potential performance improvements more quickly. The Notice of Proposed Rulemaking was issued alongside an order for NERC to audit the compliance monitoring and enforcement programs of all regional entities. (See FERC Orders Audits of All REs by 2023.) 

NERC and the REs pushed back on the commission’s plan, claiming they would “place a burden on ERO Enterprise staff … that would outweigh any potential benefits.” Specifically, respondents warned of the time required to coordinate with REs, incorporate stakeholder feedback and gain approval from NERC’s board, and said adhering to a shorter time frame could prevent the ERO from reviewing the breadth of topics that it normally does in its assessments. 

In this year’s draft performance assessment posted for comment in April, NERC suggested that FERC terminate the proceeding. The most recent filing in the docket was from the Western Interconnection Regional Advisory Body in 2021, endorsing FERC’s proposed three-year timeline. 

FERC Considering IBR Rule Changes

The final ERO-related item in FERC’s agenda is NERC’s proposed updates for its Rules of Procedure relating to registration of inverter-based resources (RR24-2).  

NERC developed the ROP changes last year as stage 1 of its three-stage registration process approved by FERC in May 2023. They will revise the definitions of generator owner and operator to create a new category, GO-IBR, for entities that own or operate IBRs that either have or contribute to an aggregate nameplate capacity of at least 20 MVA and are connected to a common point of connection with a voltage of at least 60 kV. 

If FERC approves NERC’s ROP changes this week, the ERO’s next step will be to identify candidates for GO-IBR registration by May 2025, and then to register GO-IBRs by May 2026. 

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Stakeholders Call on CAISO to Take Larger Role in Reliability Planning

CAISO stakeholders are calling on the ISO to take a bigger role in reliability planning because of the increasingly complicated nature of ensuring reliability on the California grid in the face of climate change.  

“At this point in time, we have arguably five different agencies involved in keeping the lights on in California,” Carrie Bentley, CEO of Gridwell Consulting, said on behalf of the Western Power Trading Forum (WPTF) during a June 18 presentation to the ISO’s Resource Adequacy and Program Design Working Group.  

Key among those other agencies are California’s Public Utilities Commission, Energy Commission and Department of Water Resources, which manages the state’s strategic energy reserve. 

“We have overlapping processes that are only getting more complex over time. The coordination and processes are growing more complex because the state is not only trying to accommodate climate change, [and] plan for climate change, but it’s also trying to prevent climate change,” Bentley said.  

Because no single agency is in charge of ensuring “holistic” reliability, Bentley proposed that CAISO take on that role and, more specifically, conduct probabilistic loss-of-load-expectation (LOLE) modeling to better understand the aggregate impact of the changing climate on grid conditions.  

“This [LOLE modeling] actually allows you to say, ‘What are the impacts of all of these probabilities, all these different extreme events, and these different levers being pulled on by different agencies? What is the aggregate impact on the CAISO balancing area?’ And the only way I know to do that robustly is through loss-of-load-expectation modeling,” Bentley said.   

In addition to driving up peak load, higher temperatures are also causing “astronomical” increases in load variability, Bentley said. Between 2017 and 2023, that variability was significant enough to cause load forecasts to deviate from actual loads by several thousand more megawatts than historically normal.  

Planning processes must account for increases in variability to ensure reliability, Bentley said. And because resource planning is conducted over so many different agencies and processes, it is unclear if processes are “calibrated for climate change” or if “CAISO’s balancing area is actually reliable,” she added.  

“There is a clear and present need for not just re-evaluation of individual processes for climate change, but also to do this holistically. And we think CAISO is uniquely suited to provide this function. In fact, we think CAISO is probably the only agency that will be able to provide this function because they’re the only ones with a clear picture,” Bentley said.  

Bentley also called on CAISO to update counting rules and the planning reserve margin (PRM). 

Other stakeholders expressed support for Bentley’s suggestions.  

“This resonates incredibly … and is something we deeply need,” Cathleen Colbert, senior director of Western markets and policy at Vistra, said during the meeting. “We need to understand, what is the reliability status of the balancing authority area on a forward-looking probabilistic basis?”  

Aditya Jayam Prabhakar, director of resource assessment and planning at CAISO, reassured stakeholders that the ISO is already working to address Bentley’s two main requests: to evaluate forward CAISO reliability assessments in terms of LOLE modeling, and to update default PRM and RA counting rules.  

WPTF also requested that the ISO establish a comprehensive mothball and retirement process for generating plants based on local needs, but Bentley emphasized that the LOLE modeling should first be “stood up, and then it will naturally flow into other processes.”  

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PUCN Sets Framework for NV Energy’s EDAM Participation

As NV Energy moves forward with plans to join CAISO’s Extended Day-Ahead Market, Nevada regulators have laid out a framework for how the company can seek approval for EDAM participation. 

NV Energy should make the request through an amendment to the company’s energy supply plan, according to an order the Public Utilities Commission of Nevada (PUCN) approved June 21. NV Energy used a similar process in 2014 to get PUCN approval for joining CAISO’s Western Energy Imbalance Market (WEIM). 

And as part of its request, NV Energy should address a long list of questions posed by the PUCN, ranging from the costs to join a day-ahead market to how participation will impact revenues and rates and what a path to an RTO would look like. 

A Nevada law adopted in 2021 requires transmission providers in the state to join an RTO by January 2030. 

The PUCN opened a docket in October 2023 to explore regional market activities in the Western Interconnection. 

Commissioner Tammy Cordova, the presiding officer in the case, held three workshops this year on day-ahead market participation and invited two rounds of stakeholder comments. The workshops looked at cost-benefit studies and market design for the two competing Western day-ahead markets: CAISO’s EDAM and SPP’s Markets+. 

Meanwhile, NV Energy recently stated its intent to join EDAM and provided some of the rationale for its decision in its 2025/27 integrated resource plan filed May 31. (See NV Energy Confirms Intent to Join CAISO’s EDAM and Market Footprint Critical for EDAM Decision, NV Energy Says.) 

The company expects to file a request to join EDAM this year. 

The announcement came after a Brattle Group study this year projected that NV Energy’s benefits under EDAM would range from $62 million to $149 million in 2032, depending on the market footprint, whereas Markets+ benefits would range from a $17 million loss to a $16 million gain. 

During the commission’s June 21 meeting, Cordova said the cost-benefit analyses are just one factor to consider in a day-ahead market choice. 

“It was really important to me that we had information beyond just production-cost modeling when we would evaluate whether or not any request by NV Energy was in the public interest,” Cordova said. 

In a request to join a day-ahead market, the commission wants to hear about the market’s governance and who else plans to join. 

Other questions focus on the resiliency of the market to natural disasters or cybersecurity threats. PUCN wants to know how GHG emissions will be tracked and the impact on compliance with the state’s renewable portfolio standard. 

Another issue is the impacts on non-jurisdictional transmission customers in NV Energy’s balancing authority area. 

Other questions are the impact of joining a day-ahead market on generation development and on building new transmission.

In written comments, PUCN staff said NV Energy should be required to address “whether the potential $5 [billion] to $10 billion of transmission investments proposed for Nevada will be impacted depending on which [day-ahead market] NV Energy requests to join.” 

Staff pointed specifically to the Cross-Tie, SWIP-North, One Nevada No. 2 and TransWest projects. 

In comments filed May 30, NV Energy expressed support for the list of questions. 

“Examination of these areas will provide a comprehensive assessment of the potential benefits associated with DAM participation in general and of specifically joining the EDAM,” the company said. 

Following approval of its order June 21, the commission is largely wrapping up the day-ahead market portion of the docket. 

But in a second phase of the docket, the PUCN will be taking a closer look at RTO participation. A schedule for the RTO phase of the docket has yet to be established. 

“This docket is by no means done,” Cordova said.  

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Order Expected on Complaint Against PJM over ELCC Resource Accreditation

FERC is expected to issue an order during its June 27 open meeting on a complaint alleging PJM violated its Reliability Assurance Agreement (RAA) when accrediting intermittent resources (EL23-13). 

Filed in November 2022 by economist Roy Shanker, the complaint argues the RTO improperly included energy above intermittent resources’ capacity interconnection rights (CIRs) when determining their capacity contributions. The practice was used for resources accredited through PJM’s effective load-carrying capability (ELCC) approach. 

FERC

Consultant Roy Shanker | © RTO Insider LLC

The commission issued a March 2023 order accepting a PJM proposal intending to resolve the issue by modifying the ELCC analysis to cap the hourly output a resource is expected to be able to offer at its CIR level (ER23-1067). The commission also is slated to issue an additional order in that docket June 27. (See FERC Approves Revisions to PJM’s ELCC Accreditation Model.) 

The month prior to FERC’s order granting PJM’s proposal, Shanker argued against PJM comments asking the commission to dismiss his complaint, saying that even if the proposal resolved RAA violations going forward, that would not cure past violations. 

The complaint asked the commission to adjust prior Base Residual Auction settlements “that are not time barred” and effectively implement its proposed cap on hourly output immediately without a transitional period. It requested an effective date of Nov. 30, 2022, and refunds through the implementation of PJM’s proposal. 

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FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations

FERC has established settlement judge procedures to consider the validity of rate schedules filed by Talen Energy to continue operating its Brandon Shores and H.A. Wagner generators past their retirement date (ER24-1787, ER24-1790). (See PJM Requests 2nd Talen Generator Delay Retirement.) 

The commission’s June 17 order states that the proposed rate schedules may not be just and reasonable because of the calculation of the filings’ valuations of the two generators. It also took issue with adjusting fixed operating and maintenance expenses for inflation using an escalation index, along with the proposed monthly project investment tracker payment and performance requirements. 

“While we are setting these matters for a trial-type evidentiary hearing, we encourage the parties to make every effort to reach settlement before hearing procedures commence,” the order states. 

The filings requested annual fixed costs of around $175 million to keep Brandon Shores’ 1,273-MW coal-fired generator online from June 1, 2025, through Dec. 31, 2028, as well as variable costs such as fuel and $29.9 million in project investments. The Wagner filing requests $40.3 million annually to keep two of Wagner’s oil-fired units, amounting to 702 MW, online for the same period and $4.5 million in additional investments.  

The reliability-must-run (RMR) agreement is intended to keep the generators online to avoid reliability violations identified throughout the Baltimore region while transmission reinforcements are constructed that would allow the units to deactivate without issue. (See FERC Approves Cost Allocation for $5 Billion in PJM Transmission Expansion.) 

The proposed rates were opposed by the Independent Market Monitor and the Maryland Public Service Commission, who argued the rate schedules would improperly include sunk costs incurred prior to the start of the RMR term and unrelated to the going-forward costs of keeping the facilities operational. 

The Monitor argued that including sunk costs that have already been reported as impaired assets would ask ratepayers to make investors whole for past losses. 

The June 17 order accepted the rate schedules, suspended them and initiated the settlement judge procedures with the possibility of evidentiary hearings if that avenue does not yield a consensus. 

Maryland Deputy People’s Counsel William Fields said sunk costs make up a significant portion of the proposed rates and the Office of People’s Counsel is preparing an analysis on how the RMR could affect state ratepayers. He said the office is pleased with the commission’s decision to open settlement judge procedures and plans to fully participate. 

“We don’t view those as costs that are related to going forward with operations of the plant.” 

Fields said he believes PJM’s backlogged generation interconnection process leaves few alternatives to expensive RMR contracts to keep retiring resources online while major grid reinforcements are constructed. 

“We’ve got a few concerns with that approach or reliance on the market response here, and one is that this happens very quickly. You’re talking months, and that is very, very quick for any kind of significant market response to a significant, pretty big retirement. Trying to respond to that with a lot of megawatts is going to be difficult in any circumstance, and right now, the PJM queue process is working through its backlog, and that makes it even more difficult for some kind of new resource to get through and get online on a time frame that’s going to help the situation at all,” he said. 

Protesters also disputed the filings’ methodology for determining the value of Brandon Shores and Wagner, depreciation and the amount of risk the company faces in continuing to operate the generators. 

Monitor Joe Bowring said opportunity costs similar to those Talen is seeking to include in the rates have been rejected by the commission in past RMR filings. 

The Brandon Shores filing also notes it’s subject to a settlement agreement with the Sierra Club requiring that coal combustion at the site cease by the end of 2025. It states that it will seek changes to those terms to allow the generator to keep operating for the RMR term. 

Casey Roberts of the Sierra Club said the organization is willing to engage with Talen on the agreement, but “additional protections for the local community and consumers, and longer-term reforms to avoid similar predicaments in the future, must all be on the table.” 

The club’s protest of the rate schedule also urged the commission to not approve an RMR agreement that would pay for Brandon Shores to remain online until the agreement has been modified to allow the generator to operate. 

“Thus, it appears on the face of the CORS [continuing operations rate schedules] that Talen intends not to operate Brandon Shores under the CORS unless its settlement agreement with Sierra Club is modified, notwithstanding the hundreds of millions of dollars in fixed monthly payments that Talen would receive even if it never generates a single megawatt hour. FERC cannot approve such an arrangement, particularly on the expedited basis that Talen seeks in this proceeding,” the Sierra Club wrote. 

Both the Sierra Club and Maryland Public Service Commission argued that the proposed rates lack performance requirements and would require load to pay significant sums to keep the two generators operational with no guarantee they would respond if dispatched by PJM. 

Maryland PSC spokesperson Tori Leonard said the commission supports FERC’s directive opening the settlement judge proceedings. 

“FERC’s preliminary analysis confirmed that both the Brandon Shores rate schedule and Wagner rate schedule have not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” Leonard wrote in an email. “This commission is pleased that FERC granted our request (as well as the request of the Maryland Office of People’s Counsel), to set the matter for settlement judge procedures. The commission will continue to advocate for a reasonable resolution of the Brandon Shores and Wagner RMR filings that will minimize impacts to ratepayers, while preserving the reliability of the bulk electric power system to serve Maryland’s needs.”