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January 16, 2025

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DC Circuit Rejects Challenge to FERC Approval of Indiana Pipeline

A three-judge panel of the D.C. Circuit Court of Appeals issued a decision Jan. 7 that sided with FERC in an appeal of the agency’s decision approving a natural gas pipeline in Indiana. 

The pipeline was proposed to serve new natural gas units the state had approved to replace a retiring coal plant. Citizens Action Coalition of Indiana argued that FERC failed to analyze non-gas alternatives before approving the pipeline. 

“We disagree,” the court said. “Congress gave FERC authority to promote the development of interstate natural gas pipelines, but it left the choice of energy generation to the states. The purpose of the pipeline was to support Indiana’s energy plan, and FERC has no statutory authority to consider non-gas alternatives already rejected by the state.” 

The win by FERC follows losses on other pipeline cases at the D.C. Circuit, including a New Jersey one in which the commission approved new pipeline capacity that the state opposed on the grounds that it clashed with its climate policies. (See DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections.) 

The Natural Gas Act requires FERC to approve a pipeline if it determines the project is “required by the present or future public convenience and necessity.” It also can approve a project when its public benefits outweigh its adverse impacts. 

Indiana regulators in 2017 approved CenterPoint Energy’s integrated resource plan, which included a proposal to replace coal generators at its A.B. Brown Generating Station with solar and natural gas facilities. The utility initially wanted an 850-MW gas-fired unit, but state regulators rejected that plan and approved two smaller gas turbines that together produce 460 MW. 

“That brings us to the pipeline at issue here,” the D.C. Circuit decision said. “CenterPoint contracted with Texas Gas Transmission to supply natural gas to the planned units. Texas Gas then applied to FERC for approval of a 24-mile pipeline crossing the Ohio River and connecting the A.B. Brown site to an existing pipeline system in Kentucky.” 

FERC approved the pipeline after performing an environmental impact statement. Citizens Action filed for rehearing on the grounds the commission failed to consider alternatives to the gas units, failed to determine the impact of emissions, was wrong to net the drop in emissions from replacing coal with gas, and failed to properly balance environmental impacts with its public convenience and necessity determination.

The National Environmental Policy Act does not require FERC to consider non-gas alternatives that are outside its jurisdiction and would fail to serve the purpose of the project. 

“The project seeking certification from FERC is not the natural gas units, but the pipeline serving those units,” the court said. “Before Texas Gas applied for a certificate, CenterPoint and the Indiana commission had already determined that the public interest would be best served by the construction of natural gas units that ensure grid reliability and support the move to wind and solar generation.”  

FERC rejected Citizens Action’s request that the project be defined as promoting solar and wind, saying detailed evaluations of other power generation alternatives are separate questions from the pipeline proceeding. 

“More to the point, FERC could not lawfully define the project’s purpose as broadly as Citizens Action requests because Congress has not authorized FERC to choose between electricity generation resources,” the court said. “The NGA empowers FERC to approve new gas pipelines. It does not permit FERC to regulate the energy generation facilities those pipelines supply.” 

States have the authority to choose their preferred mix of generation, leaving the CenterPoint turbines outside of FERC’s jurisdiction, the court found. 

FERC did assess whether the gas turbines could be served adequately by existing pipelines and looked into alternative routes, which the court said showed it “adequately considered alternatives.” 

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Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO

FERC authorized another hefty penalty concerning demand response violations in the MISO capacity market, this time approving an $18 million settlement over Voltus reportedly falsifying registrations and overstating capacity from 2016 to 2020.

Voltus — the first retail customer aggregator to participate in MISO capacity auctions — and FERC finalized a settlement Jan. 6 that has Voltus paying a $10.9 million civil penalty and reimbursing $7.1 million in profits to settle allegations that the company manipulated MISO’s demand response market (IN21-10). The settlement also directs Voltus co-founder and former CEO Gregg Dixon to pay a $1 million fine and step down from the Voltus Board of Directors.

Additionally, Voltus must file annual compliance monitoring reports to FERC enforcement staff for two years, with the potential for another two years of monitoring reports beyond that.

Voltus announced in early 2024 that Dixon stepped down as CEO but would remain on the company’s board of directors.

FERC’s Office of Enforcement concluded Voltus inappropriately gained access to customer data and used it to deceptively register load-modifying resources over four MISO capacity auctions. It said both Voltus and Dixon cooperated with its investigation, which began in 2021.

FERC staff said under Dixon’s direction, Voltus employees registered Ameren Illinois ratepayers as load-modifying resources without their knowledge or consent. Employees used Ameren account numbers on the utility’s website to download data required by MISO to register them.

Dixon reportedly learned from an employee sometime before MISO’s 2017/18 capacity auction that non-public data on Ameren’s customers could be obtained by registering as an Ameren business partner and then entering customer account numbers on its website.

According to Dixon, Ameren had “advanced metering infrastructure and meter data available” that enabled Voltus to “measure performance for dispatches of demand response without having to install our technology.”

Voltus in late 2016 rolled out what it called “Operation Violet” with a goal of selling 200 MW of demand reduction in MISO’s Zone 4 in southern Illinois. Voltus in some cases requested copies of Ameren customers’ utility bills to conduct analyses of what they could earn by participating in DR, FERC said, and noted that the bills contained account numbers.

For legitimate customers who entered Voltus’ aggregation program, FERC staff said Voltus employees — again at Dixon’s direction — would inflate on paper the levels of curtailment that the customers agreed to provide. FERC said Voltus employees registered some resources as if they would completely shut down if called upon without regard to whether that was possible or whether resources had agreed to it in their contracts.

According to FERC, a third-party contractor Voltus hired to help manage demand response registrations reportedly became uncomfortable over the possibility for fines and the “reputational risk for Voltus” and resigned in early 2017.

‘Scranta’

By summer 2017, Voltus had designed a computer program named “Scranta” based on a portmanteau of “scrape” and “Santa,” which scraped data from Ameren by submitting “tens of millions” of potential account numbers to the website. When the program landed on a genuine account number, it would collect customer data for a Voltus database.

When Voltus found accounts with peak demand above 50 kW, those accounts were added to an automated email distributed to Voltus leadership and a sales team to either become leads or involuntary participants in Voltus’ demand response program.

FERC said a Voltus employee sent an August 2017 email stating, “We should exercise caution increasing the scraping rate, as it would be very easy for [Ameren] to make this much harder for us with some simple server config changes.”

FERC said in its first MISO Planning Resource Auction for 2017/18, Voltus registered about 41 MW of load modifying resources without contracts. After rolling out Scranta, Voltus registered an uncontracted 207 MW with MISO in the 2018/19 PRA, 216 MW in the 2019/20 PRA and 65 MW in the 2020/21 PRA. The uncontracted megawatts included some resources that Voltus approached with unsuccessful sales pitches.

FERC said uncontracted or above-contract demand response made up 96% of Voltus’ MISO portfolio in the 2017/18 planning year, 49% in the 2018/19 planning year, 45% in the 2019/20 planning year and 29% in the 2020/21 planning year. FERC said over those years, MISO didn’t require aggregators to prove they had contractual relationships with the load-modifying resources they claimed to have at the ready.

FERC staff said Dixon acknowledged in testimony that Voltus didn’t know whether its DR resources without legitimate contracts would respond to MISO dispatch by reducing demand.

“I … noticed that you could just plug in any account number, that, you know, you could go to the [Ameren] website and just plug in — you know, you could essentially script the URL. It’s a 10-digit account number code. You could plug that in, just cycle through them, and it would identify — we created a program that would identify any loads,” Dixon told FERC staff during the investigation.

In an early 2019 Slack conversation with Voltus employees, Dixon likened the unauthorized DR registrations to his hobby clearing mountain biking trails on a nature preserve. Dixon said because he didn’t have explicit permission to cut new paths, he would work under the cover of darkness to clear brush.

An unnamed Voltus employee reportedly responded with, “If we sat around waiting for MISO to create the perfect rules for DR and always played by their exact rules there wouldn’t be DR in MISO at all!”

Parallels with Ketchup Caddy

The settlement is the latest in a string of disciplinary action from FERC regarding companies deceptively offering demand response in MISO’s capacity auctions.

This also is the second time Ameren’s website has been connected to phony demand response schemes in MISO. From 2019 to 2021, the founder of an obscure, Texas-based LLC meant to sell in-car ketchup holders used a random number generator on an Ameren website to land on actual customer accounts and cull data for fraudulent DR registrations. (See In a Pickle: FERC Issues $27M in Fines over Ketchup Caddy DR Deceit.)

Ameren did not return RTO Insider’s request for comment on whether it has addressed vulnerabilities within its website that allow companies to use random number generators to reveal customer account numbers and gain access to usage data.

Voltus Neither Admits nor Denies

Voltus said the settlement should not be construed as it admitting to market manipulation.

“Under the terms of the settlement agreement, we are not acknowledging wrongdoing in connection with bringing demand response to MISO for the first time. We have not been accused of, let alone admit to, any market manipulation. Rather, we are entering a no-admit/no-deny settlement on tariff violations. Moving forward, we will continue to act according to the letter and spirit of all applicable laws, regulations and market rules,” the company said in an emailed statement to RTO Insider.

In its order approving the consent agreement, FERC cited the conclusions of an investigation by its enforcement office that singled out Dixon: “Enforcement has concluded that Dixon violated the Anti-Manipulation Rule, 18 C.F.R. § 1c.2, during the Relevant Period by engaging in a fraudulent scheme to obtain capacity payments from MISO that included (1) improperly obtaining customer data and using that data in connection with jurisdictional transactions, (2) registering LMRs to which Voltus lacked contractual rights, and (3) offering uncontracted LMRs into the PRA. Enforcement has concluded Dixon made, and allowed Voltus employees under his control to make, false and misleading statements to MISO, customers and potential customers, and others, in furtherance of this fraudulent scheme. Enforcement has concluded Dixon knew, or was reckless in not knowing, that this fraudulent scheme violated the terms and requirements of the MISO Tariff.”

Voltus said with the settlement behind it, its “team is free to put its undivided focus on creating opportunities for customers and on delivering a more reliable, affordable and sustainable electric grid.”

“Voltus will continue to work with regulators, including FERC, to ensure that tariffs that govern demand-side resources are clear and consistently applied,” the company said.

Voltus said it remains proud of the $175 million it has paid customers over the past nine years, “much of which comes from markets that previously did not allow demand response.”

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WAPA Sued Over 504-MW Wind Farm Interconnection Plan

A lawsuit seeks to block interconnection of what could become Wyoming’s largest wind farm, alleging an inadequate environmental review of the interconnection plan. 

The 504-MW Rail Tie Wind Project being developed by Repsol Renewables would have negative effects on local eagle populations and on the wide-open vistas in the area, the plaintiffs argue. 

They fault the Western Area Power Administration for this and are asking the court to set aside WAPA’s Record of Decision, Final Environmental Impact Statement and Historic Properties Treatment Plan. 

The lawsuit was filed in federal court in Wyoming on Dec. 23 against WAPA and Jennifer Granholm in her role as head of the U.S. Department of Energy, WAPA’s parent agency. As of Jan. 7, there was no indication in the federal court system’s public records portal of any reply by WAPA or DOE. 

The project would occupy 26,000 acres south of Laramie, near the Colorado border, and would interconnect with WAPA’s Ault-Craig 345-kV transmission line. 

WAPA published an environmental impact statement in late 2021, as required by the National Environmental Policy Act (NEPA), and issued its record of decision in mid-2022. 

On Oct. 28, 2024, WAPA issued a seven-point mitigation action plan that called for measures including a one-mile buffer zone around known eagle nests, preparation of an eagle conservation plan and funding for historic preservation efforts in the area, which has a connection to construction of the original transcontinental railroad. 

Two months later, attorneys for the plaintiffs — who are two neighbors of the site; a retired wildlife biologist who has placed satellite tags on 152 golden eagles for research purposes; a conservation nonprofit; and a professional archaeologists’ association — filed their suit in federal court in Wyoming. 

They assert and allege that: 

    • Rail Tie would be larger than any wind farm now operating in Wyoming. 
    • Construction would entail 60 miles of new roads, 109 stream crossings and 84 to 149 wind turbines standing 500 to 675 feet tall. 
    • By WAPA’s own admission, operation would present a “significant” threat to raptors including federally protected bald and golden eagles. 
    • The impact statement acknowledges that the size and number of turbines used in the project is unknown, so the analysis is based on “guesswork adorned with rhetorical misdirection.” 
    • WAPA “shrugs off any serious consideration of those effects” by deferring analysis to reports that will not be completed until many years after the NEPA process is completed, if at all. 
    • WAPA considered only two options — denying the interconnection request or approving it in its entirety. 
    • The next-closest 345-kV line is approximately 20 miles from Rail Tie’s sprawling footprint; connecting to that rather than to WAPA’s Ault-Craig line would cost at least $21.5 million and skew the economics of a project already expected to cost more than $500 million. 

The plaintiffs are asking the court to enjoin WAPA from authorizing interconnection of Rail Tie until the agency has complied with all of its obligations under federal law. 

The Rail Tie project website indicates the developer has been through review at the county, state and federal levels; has secured all major permits needed; is focused on final engineering and reconstruction activities; is finalizing an offtaker for the electricity the project would produce; and expects to start construction this spring. 

If it is completed as planned, Rail Tie would continue a striking transition in the nation’s leading coal-producing state: Since 2015, Wyoming’s coal production is down by nearly 40% while its wind power production has more than doubled, according to the U.S. Energy Information Administration. 

Southeast Wyoming — including Albany County, where Rail Tie would be built — has among the strongest wind resources in the nation, with swaths rated “excellent,” “outstanding” and “superb” under the Department of Energy’s WindExchange rating system. 

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NYISO Publishes Final Capacity Requirements for CY25/26

NYISO presented its final locational minimum installed capacity requirements for the 2025/26 capability year during the Installed Capacity Working Group’s first meeting of 2025 on Jan. 7, with only slight differences from the previous CY. 

The LCRs, expressed as a percentage of the peak load forecast, represent the minimum capacity that New York’s generators and load-serving entities must maintain within each of the downstate zones, which have transmission constraints. 

2025-2026 final LCR results | NYISO

Based on the 24.4% installed reserve margin approved by the New York State Reliability Council, NYISO determined the minimum capacity required for New York City, Long Island and the Lower Hudson Valley to be 78.5%, 106.5% and 78.8%, respectively. For CY24/25, they were 80.4%, 105.3% and 81%, respectively, based on a 22% IRM. 

NYISO also presented updated informational capacity accreditation factors (iCAFs) for CY25/26. The final CAFs will be calculated and posted by March 1.  

The iCAF values generally were lower than the initial ones presented in early October. NYISO staff said this was because of an increase in the loss-of-load expectation. The exception to this was solar, which generally saw an increase in value. 

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After Budget, Energy Could be a Top Priority for Md. Lawmakers

When the Maryland General Assembly opens its 2025 session Jan. 8, lawmakers’ top priority is expected to be the state’s looming budget deficits, estimated at $1 billion this year, $2.7 billion in 2026 and close to $6 billion by 2030, according to state budget analysts.  

Energy, however, could be a close second, according to some lawmakers and advocates, who are preparing to introduce a range of bills, from initiatives requiring all new buildings in the state to be energy efficient and electrified to mandates for utilities to undertake comprehensive distribution system planning every three years. 

These and other potential bills were the focus of an online summit Jan. 4, hosted by a group of energy and environmental advocacy groups, including the Maryland Legislative Coalition, the Sierra Club and ShoreRivers, an Eastern Shore environmental group. 

The focus on energy comes as Maryland looks at how to close the budget gap, meet its ambitious climate and clean energy goals, and keep utility bills low for consumers, all while importing 40% of its power from the regional grid operated by PJM. The Climate Solutions Now Act of 2022 commits the state to a 60% cut in greenhouse gas emissions, below 2006 levels by 2031, and Gov. Wes Moore (D) has set a 100% clean energy target for 2035. 

“Success in addressing environmental issues, and especially climate change, demands policies that are consistent with customer interests,” said People’s Counsel David S. Lapp, the state’s chief consumer advocate, during his keynote presentation at the summit. “Efforts to address the climate that disregard customer interests and economic justice are doomed to failure and get and give environmentalists a bad name. 

“Fortunately, many of the most effective climate policies also promote customer interests, though they may be politically challenging as they often require taking on powerful corporate interests.” 

A case in point is Del. Vaughn Stewart’s (D) Reclaim Renewable Energy Act (H.B. 220/S.B. 10), which would amend the state’s renewable portfolio standard to exclude waste incineration as a source of renewable generation.  

“It’s the simplest bill in the world,” said Jennifer Kunze of Clean Water Action, a nonprofit working with Stewart on the bill. “It just deletes two lines of code from the definition of renewable energy for the Renewable Portfolio Standard — ‘waste to energy’ and ‘refuse-derived fuel,’ both of which are different ways for describing different forms of trash incineration, and that is all the bill does.” 

But with millions in state subsidies paid to Maryland’s three major incinerators at stake, similar bills have been introduced and failed eight years in a row, Kunze said. The goal is to free up those millions to support more “actual” renewable energy, like wind and solar, she said. 

“This bill won’t create a trash crisis where we don’t have anywhere to put the trash, because it will not shut the incinerators down right away,” Kunze said. “It is part of right-sizing the waste markets and making sure that as we’re trying to move away from trash incineration, [we are] building businesses and programs that can handle our waste in more sustainable means.” 

Other bills being reintroduced in the 2025 session include: 

    • Del. Adrian Boafo’s (D) Better Buildings Act, which would require all new construction in the state to be energy-efficient and electric. Parts of the law originally were in the CSNA but were removed in negotiations to get the law passed, Boafo said. 
    • The GREEN Act, another Boafo bill, which would establish a state fund to provide no-interest loans to small nonprofits, with budgets under $1 million per year, to help them finance energy efficiency and renewable energy upgrades. The Senate has passed a version of the bill each of the past three years, and Boafo hopes to get it through the House in 2025.
    • Del. Andre Johnson’s (D) Utility Transparency and Accountability Act, which stalled out at the end of the 2024 legislative session. It would prohibit the state’s utilities from using ratepayer funds for political activities. ranging from direct political donations and lobbying to membership fees for industry trade associations. 

Build Battery Storage Now

The rising opposition to the Maryland Piedmont Reliability Project, a 67-mile, 500-kV transmission line, and general dissatisfaction with PJM and utility grid-planning and interconnection policies, also are driving several new bills. 

PJM says the line is essential to prevent system collapse or blackouts in Maryland in the coming years, as coal plants in the state are retired. But opponents say the line will disrupt farmland and communities along its proposed route in Baltimore, Carroll and Frederick counties, without providing major benefits to the state.  

The Public Service Enterprise Group, the New Jersey-based utility building the project, filed an application for a certificate of public convenience and necessity with the Maryland Public Service Commission on Dec. 31. (See PSEG’s Piedmont Transmission Project Faces Opposition in Maryland.) 

Del. Lorig Charkoudian (D) is tackling the problems underlying the MPRP with the Abundant and Affordable Clean Energy Act, which aims to increase carbon-free generation in the state via a multipronged approach. First, the law would create an emergency procurement for energy storage, which would allow energy storage in the PJM queue to get connected in Maryland over the next three to five years, Charkoudian said. 

“If we build battery storage now, it buys us the time to think clearly about our energy future and to bring on additional clean energy and to not rush toward a somewhat reckless path of building a new gas plant before, one, we know it’s needed and, two, putting that kind of a thing on our ratepayers,” she said. 

Other provisions in the bill would revise solar renewable energy credits and introduce a competitive process for onshore wind projects, in both cases to encourage the construction of more clean energy projects in or near Maryland. It also would support the relicensing of the Calvert Cliffs nuclear plant and dedicate 75% of state sales and franchise taxes from new data centers to pay for clean energy projects. 

Del. Lily Qi (D) plans to introduce the Affordable Grid Reliability and Improved Distribution (GRID) Act, complementary legislation focused on distribution planning. This bill would require utilities to submit comprehensive distribution system plans to the PSC every three years “utilizing bottom-up load forecasting that incorporates developments in vehicle and building electrification and the goals of state and local decarbonization policies,” according to a bill summary from the summit.  

The distribution plans would have to be supported with appropriate investment strategies, as well as operational objectives that prioritize the needs of communities already overburdened with pollution from energy generation and optimize the siting of distributed energy resources.  

Sen. Karen Lewis Young (D) has two bills aimed at data center and transmission planning. The first would mandate a “robust” study of data centers’ potential impacts in the state, looking at economics, GHG emissions and energy demand.  

Lewis Young said the economic benefits and jobs predicted for specific data centers often are based on inconsistent numbers and may vary across regions. While the Maryland Tech Council has done some analysis about planned data centers in Frederick County, Lewis Young, who represents the area, wants a second opinion, with the Department of Legislative Services and the University of Maryland on board to direct the analysis. 

A second grid enhancement bill would require utilities to prioritize optimizing capacity on their existing transmission and distribution systems through grid-enhancing technologies and “other means of reducing green-field transmission construction,” Lewis Young said. 

“It will require local utility companies to submit a report to the PSC … [to] forecast load growth, their plans and resources to meet the growing demand, a list of projects they are working on with PJM and what they’re doing to connect renewable generation to their grid,” she said. 

The bill is intended to increase transparency, accountability and local input, Lewis Young said. “The thoughts … about transmission lines in Frederick County could be different from Baltimore versus Carroll or Howard. So, we need that local perspective.” 

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NYPA Files Petition with New York PSC to Save Clean Path Project

The New York Power Authority on Dec. 23 filed a petition with the Public Service Commission asking it to designate Clean Path NY as a Priority Transmission Project (PTP) under the Accelerated Renewable Energy Growth and Community Benefit Act.

The $11 billion Clean Path’s agreement between the developers and the New York State Energy Research and Development Authority was terminated in November. (See $11B Transmission + Generation Plan Canceled in NY.) The project is a public-private collaboration of NYPA and Forward Power, which is a joint venture of energyRe and Invenergy.

It would consist of 178 miles of HVDC line between Delaware County and Queens to bring 3.8 GW from 23 new solar and onshore wind projects to New York City. The line is engineered to be bidirectional so that offshore wind could serve upstate load when needed.

The November announcement led many to assume the project was effectively dead. But “it’s important to remember that a NYSERDA contract cancellation does not equal a project cancellation,” wrote Marguerite Wells, president of the Alliance for Clean Energy New York. “As we saw with many clean energy generation projects over the last couple of years, developers continued advancing projects after a contract cancellation, and many of them have since secured new contracts. This filing shows that the idea and development of Clean Path continues.”

PTPs are projects deemed necessary on an “expeditious” basis to access and deliver renewable energy resources, and they are referred to NYPA exclusively for development.

“Expedited development of the Clean Path transmission project is critical to advancing the state’s achievement of the aggressive” mandates of the Climate Leadership and Community Protection Act (CLCPA), NYPA wrote in its petition.

But PTP designation would not save the entire project. The NYSERDA contract included the 23 new renewable facilities.

“Our proposal would accelerate development and address the state’s need to transmit upstate renewable energy directly into New York City, reducing congestion to support the decarbonization of the electric system in line with the state’s climate goals,” NYPA spokesperson Lindsay Kryzak said in a statement. “NYPA awaits a decision on its petition by the PSC.”

NYPA estimated the project would reduce emissions and produce cost savings to ratepayers both in terms of capacity payments and congestion payments to the tune of about $6.2 billion over 23 years. This would help the state meet its climate goals by increasing the availability of renewable energy downstate while bypassing the relatively slow project planning processes of NYISO and the PSC, it said. It also argued a new project would not be selected until mid-2027 at the earliest, delaying the in-service date until after 2030.

NYPA estimated it can complete the project before 2030 if the petition is approved. It cited many planning and interconnection hurdles that are finished or well in progress, including federal applications, NYISO interconnection studies and pre-secured fabrication slots with cable manufacturers.

It also cited NYISO’s most recent Reliability Needs Assessment that found a reliability need in New York City starting in 2033. Furthermore, NYISO estimates that by 2030 the system will transition from a summer peak to a winter peak.

The Champlain Hudson Power Express line, which will inject hydropower from Quebec to the city, should be in-service by then but is not obligated to deliver capacity to New York during the winter. 2030 also is the deadline for meeting some of the emissions targets of the CLCPA.

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PJM Capacity Market in Flux Going into 2025

Two years after PJM CEO Manu Asthana warned stakeholders the RTO will have to move quickly to ward off a reliability crisis brewing around 2030, the Board of Managers stated a capacity shortage now could come as early as the 2026/27 delivery year.

PJM begins 2025 with several proposals before FERC seeking to rework its capacity market and generator interconnection queue, while stakeholders work on an expedited Quadrennial Review of the market and changes to resource accreditation.

Two capacity auctions are scheduled for 2025 following several delays: The Base Residual Auction for the 2026/27 delivery year is set to be conducted in July, with the auction for the following year scheduled for December. The rules for those auctions, however, remain unclear amid the ongoing stakeholder processes and pending proposals.

While those changes are being considered, consumer advocates argue there is a break between capacity prices and the ability for developers to bring new resources online to lower prices. In a complaint to FERC, they make a case that so long as that gap persists, PJM’s Reliability Pricing Model (RPM) cannot deliver capacity in a just and reasonable manner. (See Consumer Advocates File Wide-ranging Complaint on PJM Capacity Market.)

One of the pillars of the advocates’ complaint is that capacity supply is being suppressed by several categories of resources being exempt from the requirement that all resources offer into the market, which would be addressed by a PJM proposal to expand the requirement to intermittent, hybrid and storage resources. Some stakeholders have advocated for the change on the basis that capacity is being withheld from the market, while renewable developers have pushed back, saying that making a change of this magnitude on such short notice could have a chilling effect on development.

Another PJM proposal would model the output of the Brandon Shores and H.A. Wagner generators outside Baltimore as supply. Both units left the market for the 2025/26 auction to operate on reliability-must-run agreements, which the Independent Market Monitor said was a major component in the substantial increase in clearing prices (ER25-682). (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

The proposal also would establish criteria for determining when an RMR unit can be counted as supply, limiting the practice to the next two delivery years and applying only to resources that can meet the needs of the transmission constraints they are being retained for while also retaining operational flexibility to provide capabilities akin to capacity. PJM told FERC it intends to pursue a more long-term solution to how RMR agreements interact with the capacity market.

The third prong of the filing would add language stating that resources that are categorically exempt from the requirement that market sellers offer into the capacity market do not hold “safe harbor against allegations of the exercise of market power that benefits an affiliated portfolio of market manipulation power.”

Queue Proposals

Another pair of filings propose to create expedited processes for new resources to proceed through the interconnection queue.

The Reliability Resource Initiative (RRI) (ER25-712) would allow 50 resources to be added to the Transitionary Cycle 2 queue, which PJM is about to begin studying. Projects would be scored and prioritized based on their capacity and effective load-carrying capability (ELCC) ratings, impact on zones facing capacity shortfalls, constructability and transmission headroom availability. PJM said it is meant to be a “one-time” solution that could allow about 10 GW of unforced capacity to quickly come online to address projected capacity shortfalls toward the end of the decade.

The RRI has been met with a mixed response from stakeholders, with some generation owners saying it would allow them to bring shovel-ready projects and uprates to existing resources to the market, while those with projects that have been in the queue for years have argued it would amount to cutting in line and discriminatory treatment. (See PJM Stakeholders Wary of Expedited Interconnection Proposal.)

PJM also proposes changes to its surplus interconnection service (SIS) process, which allows accelerated interconnection studies on projects co-located with existing resources that would improve their average output without exceeding the site’s capacity interconnection rights (CIRs). The changes would loosen the eligibility rules to allow projects that would require network upgrades, consume transmission headroom or result in “material adverse impacts” on short circuit and thermal limits. It would also expand SIS to apply to planned resources not yet completed.

And PJM plans to file in January yet another proposal, to create a parallel process for resources that would replace a deactivating generator at the same point of interconnection. The new process would take advantage of CIRs from deactivating generators to construct a new resource.

Endorsed by stakeholders in October, the proposal would create a nine-month timeline from when a developer submits an application to the drafting of an interconnection agreement. It would allow projects with minor network upgrades to proceed, including storage resources — a sticking point throughout the stakeholder deliberations.

Quadrennial Review Could See Changes to Demand Curve

To address the longer-term concerns PJM and its members have with the capacity market design, the Quadrennial Review of the market has been moved up by one year, with the aim of submitting a filing at FERC in the third quarter.

Through a handful of conceptual meetings in the fall and winter, the Brattle Group laid out its thinking on the demand curve and reference resource. In the most recent Quadrennial Review, PJM shifted to a combined cycle for the reference resource over a combustion turbine, but it has sought to reverse that in one of its capacity market proposals.

That change was proposed out of a concern that higher energy and ancillary service (EAS) revenues for CCs would lead to the net cost of new entry (CONE) falling to zero for some locational deliverability areas. Several additional parameters use net CONE as an input, including the penalty rate for generators that fail to perform during an emergency, compensation of black start units and the overall shape of the demand curve. The 2026/27 auction would be the first to use a CC reference resource.

Brattle also is exploring the possibility of PJM shifting from a variable resource requirement (VRR) curve to a marginal reliability impact curve, which could improve price stability and be adaptable to a sub-annual design if that is sought in the future. The design could yield a flatter demand curve, one of the major concerns stakeholders have voiced about the VRR curve, particularly as EAS revenues are projected to rise.

Data Center Growth Driving Transmission Upgrades

On the transmission side, PJM is grappling with how to supply rising load growth in the east, particularly around “Data Center Alley” in Northern Virginia, with new generation expected to come online in the west.

Staff have announced their intention to recommend a $5.8 billion package of Regional Transmission Expansion Plan upgrades to the board, with a vote on approval expected in the first quarter. (See “PJM Unveils Recommended Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Dec. 3, 2024.)

In Transmission Expansion Advisory Committee presentations on the recommended project components, PJM staff said one of the factors it weighed in its selections was expandability because of the likelihood that additional grid reinforcements will be needed as load growth continues.

Presentations to the RTO’s Load Analysis Subcommittee on the preliminary 2025 Load Forecast included several transmission owners projecting tens of gigawatts of large load additions (LLAs). Those additions represent expected load growth not captured in PJM’s standard economic load growth models, but consumer advocates have argued the process by which they are included requires more transparency.

Bill Fields, deputy of the Maryland Office of People’s Counsel (OPC), said the transparency and standardization of data center load projections will be a major focus for advocates going forward. He said it is unclear how PJM is vetting LLAs, and he is concerned that developers scoping out one project across multiple utilities could lead to speculative or duplicative additions making it into the forecasts.

Consumer Advocates Seek More Capacity Market Changes

Consumer advocates laid out their own priorities at a December meeting of the PJM Public Interest and Environmental Organizations User Group (PIEOUG), including incentivizing storage and demand response participation in the capacity market, a sub-annual market design and changes to RTO governance. (See Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros.)

Fields said there are roadblocks limiting the participation of DR and storage resources, both of which have been the subject of stakeholder discussions in recent months. The Market Implementation Committee has been examining the winter availability window for DR, which defines the hours in which the resource is considered available for dispatch for capacity emergencies in ELCC modeling. Curtailment service providers have argued the window limits consumers with a flat load profile from responding in winter.

The Markets and Reliability Committee voted to delay action on a PJM issue charge to establish rules for storage as transmission assets in October, with several stakeholders suggesting that the membership is saturated with work. Speaking at the Dec. 10 PIEOUG meeting, Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates are broadly supportive of expanding storage development, and they may seek changes to market rules through the PIEOUG.

Fields said it’s hard to see how PJM’s capacity market filings will be enough to address the concerns that advocates have with the market. While the RRI would allow some projects to progress and mitigate high prices, a mechanism is needed to keep prices reasonable so long as capacity prices cannot result in an actionable price signal, he said.

Under normal circumstances, PJM’s filings would constitute years’ worth of stakeholder attention and effort, not concentrated into a few months. Adequate analysis will be needed to ensure stakeholders understand the possible market impacts and to identify any unintended consequences, Fields said.

Capacity Accreditation

While several stakeholder efforts are focused on overhauling aspects of the capacity markets, they also continue to fine-tune the redesign to come out of the 2022 Critical Issue Fast Path (CIFP) process.

Three issue charges introduced by LS Power in the fall focus on the marginal ELCC accreditation methodology at the heart of the CIFP changes and are being worked on through the newly formed ELCC Senior Task Force. It is charged with considering the process’s transparency, how it contributes to resource accreditation, and a “disconnect” between the winter-focused risk modeling behind ELCC and the use of summer peaks to calculate zonal capacity emergency transfer limits.

When introducing the issue charges, LS Power argued that market participants have limited ability to understand how changes to their assets would affect their ELCC ratings. Because the framework relies on performance during past capacity emergencies, it may also take years for any improvements that could bolster capacity performance to result in higher accreditation.

LS Power’s Dan Pierpont told RTO Insider that the issue charges are just the first steps in improving ELCC; there needs to be a larger discussion on creating an accreditation framework that reflects future capability rather than historical performance. Without that, he said, the market cannot deliver a clear investment signal.

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ERCOT Faces Uphill Battle to Meet Large Loads

Known for his no-nonsense demeanor, ERCOT COO Woody Rickerson was especially candid in December when he appeared before a legislative committee overseeing the state’s grid. 

Asked to respond to a lawmaker’s concerns that assessments of Texas’ energy supplies are offering a misleadingly optimistic portrayal of the state’s energy production, Rickerson replied, “I don’t have a positive sense on this at all.” 

State Sen. Charles Schwertner (R), the joint committee’s chair and architect of many of the new laws put in place after the disastrous 2021 winter storm, asked Rickerson to clarify. 

“I don’t have a positive sense that we have enough generation on the books to serve the load that’s expected,” Rickerson replied. 

The Texas grid operator raised eyebrows last April when it said its load-growth forecasts had ballooned by 40 GW over the previous year’s estimates. It said it anticipates about 152 GW of new load by 2030. 

The state’s business-friendly environment attracts investors and developers who want to build data centers, mine cryptocurrency and employ artificial intelligence, all massive energy consumers. Industrial electrification, electric vehicles and now hydrogen facilities will only increase the strain on the ERCOT grid. The ISO has about 103 GW of installed capacity for a system that peaks around 85 GW of load in the summer and 78 GW in the winter. 

“We’re the best market in the country to react to that kind of growth potential,” ERCOT CEO Pablo Vegas said during the ISO’s April Board of Directors meeting, pointing to the ability to interconnect resources “faster than anyplace else in the country.” 

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“We continue to add generation at really an incredible rapid pace,” he told his board in December, pointing to an interconnection queue with more than 371 GW of capacity. 

Still, ERCOT has decided it had to adapt and take a different approach to meeting future demand that ensures all system-planning processes can “adapt to better serve” the state’s economy. Central to that is a new law requiring the ISO to include prospective load identified by transmission service providers, rather than factoring in unsigned load. 

Solar resources (155 GW) and battery storage (141 GW) account for 83% of the 1,775 active interconnection requests. At the same time, Texas is trying to attract more thermal generation with its Texas Energy Fund, established by state law and approved by voters in 2023.  

The fund’s In-ERCOT Generation Loan Program offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable generation. It has received 18 applications for 9.72 GW of potential new generation seeking $5.34 billion in loans; the Public Utility Commission will vet the applicants during the year before awarding the grants. 

Dealing with Growing Loads

Meanwhile, ERCOT is tracking more than 40 GW of large-load requests that may or may not show up. 

“There’s no real cost associated with saying, ‘Hey I’m a load, and I want to come to the grid,’ and there’s no forking over of ‘X’ dollars if you’re a large load, for instance,” Schwertner said during the December joint committee meeting. “We should have a great handle on what that load is, where it’s going to be added.” 

Schwertner suggested assessing an upfront fee for those wanting to interconnect their large loads with ERCOT, an issue that likely will be discussed during this year’s legislative session, which runs from Jan. 14 to June 2. 

Vegas says the current generation mix is more diverse than ever, can be built faster and is located farther from load centers. While the generation is coming online quickly and load growth increasing faster, it still takes three to six years to energize transmission in ERCOT (about half the time required in other regional grids). 

Speaking at an Energy Bar Association symposium in October, ERCOT General Counsel Chad Seely said the ISO often is asked how much its recommended transmission improvements will cost consumers and whether the new buildout will be sufficient “if all that load eventually shows up over the next five, seven years.”  

ERCOT staff continues to work with stakeholders to define rules and has completed its Permian Basin Reliability Plan, as directed by the PUC. The plan recommends five 345-kV import paths into the region and, in a first for the state, three 765-kV import paths. 

With estimated costs of $13.77 billion for the 765-kV lines and $12.95 billion for the 345-kV imports, the plan exceeds the price tags of previous annual infrastructure portfolios. Seely said the plan is necessary to meet the region’s load growth, which comes not just from oil and gas production but also data centers, crypto facilities and other large industrial users. 

“That is the equivalent of taking North Texas [and the DFW Metroplex], from a load standpoint, and putting it out in West Texas,” Seely said. “They want reliable service, so we’ve recommended a lot of transmission infrastructure, both locally and large-scale highway infrastructures.” 

Transmission providers are preparing certificates of convenience and necessity applications. The PUC has set May 1 as a date to determine which import paths will be used. 

Prompted by a 35.7% increase in projected load growth from the year before, ERCOT’s annual Regional Transmission Plan (RTP) included more than 50 GW of individual loads larger than 75 MW. Released just before the holidays, the plan includes more than 274 transmission projects and about 6,000 miles of line upgrades, rebuilds, conversions and additions to meet the forecasted load growth in the traditional 345-kV plan. In comparison, the grid operator identified a combined 262 projects in its 2023 and 2022 RTPs. 

The 2024 plan also considers a 765-kV plan as an alternative to the traditional 345-kV plans. ERCOT will file a 345-vs.-765 comparison with the PUC by late January and will host a workshop on the differences Jan. 27. 

RTC with an ERCOT Twist

After the commission shelved the once-favored performance credit mechanism market change, the ISO says its staff and stakeholders will work to complete the real-time co-optimization (RTC) project by the end of the year. Postponed after Winter Storm Uri, RTC will save about $1.6 billion annually in reduced energy costs by procuring energy and ancillary services every five minutes. (See Texas PUC Shelves PCM Design Over Lack of Benefits.) 

RTC market trials are scheduled to begin in May. The project has a December targeted go-live date.  

Once RTC becomes a part of the ERCOT market, staff will begin adding a new standalone ancillary service, dispatchable reliability reserve service. DRRS will be procured in the day-ahead and real-time markets from eligible generators who must be online within two hours of instruction and run at least four hours at their high-sustained limit. The amount of DRRS procured will reduce reliability unit commitments. 

While RTC is common in most regional grids, ERCOT is tacking in a different direction with its reliability standard. As currently proposed, the standard includes the normal one-in-10 days loss-of-load expectation found in other regional grids, but the ISO also will measure duration (no more than 12 hours in any event) and a yet-to-be-determined magnitude. (See ERCOT’s Vegas Touts New Reliability Standard.) 

ERCOT says this will result in a comprehensive reliability standard that better characterizes the real risk probabilities of a grid event and its impact on consumers. Staff are finalizing the magnitude element and working on the various parameters and scenario modeling for the new standard. 

Speaking to the Texas Reliability Entity in December, Vegas said, “We’re going to now have a yardstick that is going to effectively help us measure how we think the ERCOT market will perform in some period of time.” 

ERCOT is also working to improve its reliability must-run and must-run alternative processes, a result of CPS Energy’s attempt to retire three aging gas units this year. Staff has said the units are needed for reliability purposes and are pursuing an RMR contract for the largest resource. (See related story, ERCOT Finds Little Interest in MRAs for San Antonio Units.) 

“Some of our thermal fleet is getting quite aged,” Vegas told the board in December. He said about 40% of the ERCOT fleet is over 30 years old and 30% is over 40 years old. 

“Over time, as new resources are built and developed and brought onto the grid, you will expect the older, less economic resources to be retiring,” Vegas said. “We want to make sure that we’ve got a robust reliability must-run or must-run alternative process that we can leverage to get the most efficient and effective solutions when we are faced with that circumstance again in the future.” 

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Mass. Electricity Rates Working Group Issues Recommendations

Prior to the deployment of advanced metering infrastructure (AMI), the adoption of simple, near-term rate reforms could help Massachusetts achieve its electrification goals while minimizing effects on ratepayers, an interagency working group concluded in a report released in late December. 

The Massachusetts Interagency Rates Working Group (IRWG) recommended that each utility adopt an opt-in seasonal heat pump rate and establish a “non-bypassable fixed charge” to encompass some of the policy costs that currently are recovered through volumetric charges. 

The working group includes members of the Department of Energy Resources, the Executive Office of Energy and Environmental Affairs, the Massachusetts Clean Energy Center and the Attorney General’s Office. 

“The Working Group’s primary recommendation for the near term is for the DPU [Department of Public Utilities] to require all the EDCs [electric distribution companies] to establish a seasonal heat pump rate, similar to those recently approved and directed by the DPU for Unitil and National Grid, but with larger winter differentiation to ensure energy bill savings for customers transitioning from gas heating to electric heat pumps,” the IRWG wrote. 

Under the current rate structure, electrifying a natural gas heating system typically increases a household’s total energy costs, the group noted. It added that the cost disincentive to electrification could become more pronounced in the coming years, as both distribution and transmission rates are set to increase.  

About 54% of homes in Massachusetts use natural gas heating, 26% use oil and 13% use electric resistance, the working group noted.  

The working group recommended seasonal household-wide heat pump discounts on distribution and transmission charges. It noted that the New England power system currently peaks during the summer, and the increased winter electricity demand would be unlikely to significantly increase overall system costs. Supply rates would not be affected by the discount.  

“The winter volumetric charge of a seasonal heat pump rate can be set on a revenue neutral basis, such that, based on the expectation for increased kWh usage, the rate will still recover the same level of total fixed costs,” the IRWG wrote.  

Estimated heating cost by fuel type in Massachusetts | Massachusetts Interagency Rates Working Group

If adopted, the seasonal heat pump rate may be a short-lived design. The rollout of AMI, combined with the expected transition of the New England grid to a winter-peaking system by the mid-2030s due to heating electrification, likely will necessitate broader changes to rate design. 

The report’s other major recommendation was for a fixed charge to cover some state policy costs and system reliability costs that currently are calculated based on electricity consumption.  

While programs related to energy efficiency, decarbonization and low-income discounts historically have been funded through volumetric charges to incentivize lower energy use, high electricity rates can inhibit customers from electrifying, the report said.

“A non-bypassable fixed charge could fund crucial programs that support the state’s energy, affordability and decarbonization goals in a way that does not increase volumetric charges, a key barrier to electrification,” the working group noted.  

“These recommendations, principally the seasonal heat pump rate, can be implemented in the near term and are essential for affordability and decarbonization,” the working group added. It called on the state’s DPU to facilitate the rapid deployment of the seasonal heat pump rate for the winter of 2025/26. 

The DPU has an ongoing investigation into energy affordability and tiered discount rates (DPU 24-15). The IRWG said its recommendations are intended to be complementary to this proceeding and added that it’s considering petitioning the DPU to take up its short-term recommendations. 

The working group said it plans to issue more long-term recommendations focused on “AMI-enabled rate design, ratemaking, and regulatory mechanisms,” noting that a DPU investigation likely will be necessary for implementing these long-term changes.  

The group said the state’s three electric utilities are scheduled to complete their rollouts of AMI between 2025 and 2029, and “widespread [time-varying rates] will likely be in effect between 2029 and 2033.” 

Larry Chretien, executive director of the Green Energy Consumers Alliance, expressed strong support for the working group’s main recommendations. 

Chretien wrote that implementing the recommendations likely would require action from the DPU, adding that, “based upon some recent actions by the DPU, we anticipate that the recommendations will be met with favor.” 

“To enable a proper level of civic engagement, we encourage the DPU to consolidate the recommendations into one statewide docket,” Chretien said.  

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BPA Market Decision on Track Despite Calls for Delay

The Bonneville Power Administration remains on track to issue a decision on which day-ahead market to join by May 2025 despite calls to delay until fall to give itself more time to reconsider its leaning toward SPP’s Markets+. 

BPA spokesperson Doug Johnson told RTO Insider on Jan. 6 that the agency is “not contemplating a delay at this time,” while urging stakeholders to view recent production cost models with some skepticism.  

Johnson’s comments followed concerns presented in a Dec. 19 letter from Northwest environmental organizations that joining Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM) could lead to multimillion-dollar cost increases for the agency and its customers.  

Ten organizations, including Northwest Energy Coalition, Natural Resources Defense Council, Sierra Club and Earthjustice, signed the letter, which was published in support of four U.S. senators from Oregon and Washington who voiced similar concerns in separate correspondence with BPA. 

Antoine Lucas, SPP vice president of Markets+, said in an email that the RTO is “disappointed the letter from the Northwest NGOs perpetuates mischaracterizations of the Markets+ design, benefits and governance structure in ways that have already been addressed.” 

BPA previously stated it will issue its market decision by May 2025. The agency has leaned toward SPP’s Markets+, pointing mainly to its governance framework, which BPA believes provides greater independence from California state influence compared to the EDAM option. 

However, the environmental organizations urged BPA to delay its decision to at least fall 2025 “to accurately assess the governance structures proposed by EDAM and Markets+ and to ensure that any decision delivers the greatest economic and other benefits to our states and region,” according to their letter. 

The organizations argued that Markets+ also faces governance issues. They pointed out that FERC has yet to approve Markets+’s proposed governance structure and that the market’s independent panel “is subject to the direct control of SPP.”  

Meanwhile, the West-wide Governance Pathways Initiative, a group of stakeholders, is addressing governance concerns in EDAM by developing proposals to create an independent entity to govern the EDAM and WEIM markets, the letter stated. 

In his statement to RTO Insider, Lucas said SPP “remains confident FERC will approve the Markets+ tariff, and we look forward to continued conversations about the competitive benefits Markets+ brings to Western stakeholders and their customers.” 

Financial Considerations

BPA also participates in CAISO’s Western Energy Imbalance Market, which has “generated over $6 billion in benefits,” according to the letter. The agency’s investments in WEIM could go to waste in the Markets+ scenario, the groups contended. 

Additionally, a study by Environmental and Energy Economics found that EDAM could generate economic benefits “ranging from $65 [million to] $221 million per year compared to Markets+,” the organizations wrote. 

BPA has questioned this finding. In correspondence with Seattle City Light, the agency’s administrator, John Hairston, said these numbers are accurate only under a scenario in which there is only a single West-wide market rather than the more likely scenario that there will be multiple markets in the future.  

Johnson reiterated this point to RTO Insider, saying, “The model benefits under a single West-wide market footprint should be viewed with some skepticism.” 

“For example, a production cost model study does not capture the material impacts of resource adequacy requirements, greenhouse gas accounting, fast-start pricing, scarcity pricing, bid caps, market power mitigation, out-of-market actions and other differences in market design between EDAM and Markets+,” according to Johnson. 

He added that those models also fail to consider changes in market rules “or the lack thereof, that are influenced by a given market’s governance structure, which may impact and influence market outcomes depending on the process for updating market rules.” 

He also targeted the letter’s claim that BPA considers spending “$25 million in customer money” to fund Phase 2 of the Markets+ proposal despite expecting “to miss revenue projections for this year by $375 million, leading to $280 million in losses.” 

The letter relies on information from BPA’s second quarter business review for 2024, and Johnson said the organizations have “extrapolated that into a completely different financial operating year.” 

“We would absorb that $25 million cost if we were to execute a Phase 2 agreement with SPP this year, and we haven’t even done a first-quarter report yet, so we’re not even talking about our finances this year,” Johnson said. 

A spokesperson for U.S. Sen. Jeff Merkley (D-Ore.) — one of the four lawmakers who signed the initial letter that spurred the environmental organizations’ support — told RTO Insider that Merkley “is following this discussion closely.” 

“His priority remains ensuring there are deliberate processes to maximize the benefits for Oregon families,” the spokesperson added.