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January 16, 2025

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In Letter to Senators, BPA Tempers Markets+ Leaning

The Bonneville Power Administration tamped down expectations that it is all in on SPP’s Markets+, clarifying in a recent letter to lawmakers representing Oregon and Washington that it’s still weighing the pros and cons of joining a day-ahead market.

In a Dec. 31 letter publicly released by the agency Jan. 7, BPA Administrator John Hairston said it’s possible in the short term that BPA will not join a day-ahead market and “continue to market surplus power and make short-term purchases through bilateral trading and optimize real-time activity in [CAISO’s Western Energy Imbalance Market].”

“In the long term, we are concerned, however, that most of our potential trading partners will be in a day-ahead market themselves and create challenges in relying on a bilateral market,” Hairston added. “We will continue to evaluate the development of Western electric markets to assess the potential costs and benefits of participation.”

Hairston also reiterated that BPA would join a day-ahead market only if the market’s framework is compatible with the agency’s statutory obligations and other commitments, including environmental, reliability and affordability.

Hairston’s comments came after Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) urged in a Dec.13 letter that the federal power marketing administration carefully weigh its choice between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

Markets+ and EDAM are vying for participants as they develop their market frameworks, with BPA leaning toward Markets+. Agency staff have recommended that BPA join Markets+, citing the market’s governance framework, which BPA believes provides greater independence from California state influence compared with the EDAM option.

However, the senators contended that the agency has failed to make a business case for Markets+, citing a BPA-commissioned study by consulting firm Environmental and Energy Economics.

That study, which relied on production cost analyses, found BPA would realize the most significant net economic benefits — $251 million in 2026 declining to $147 million in 2035 — in a “Westwide Market” scenario that includes California.

In his most recent letter, Hairston echoed arguments he’s made in correspondence with Seattle City Light, telling senators the study’s results “should be viewed with some skepticism” as the Western Interconnection likely will have two day-ahead markets, given that entities have signed agreements in favor of both Markets+ and EDAM.

Hairston added that numerous other elements not captured in production cost analyses can have an economic impact on expected benefits, such as governance structure, resource adequacy requirements, greenhouse gas accounting, fast-start pricing and scarcity pricing.

The Northwest region’s EDAM supporters also have criticized BPA’s apparent willingness to dole out $25 million to fund the Phase 2 implementation activities for Markets+ while declining to contribute $25,000 to the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets.

According to the senators’ letter, SPP has said the $25 million commitment is “essentially a market decision.” Hairston rebuffed this assertion in his most recent letter, saying “Phase 2 funding is not a commitment to joining Markets+; it is a commitment to continue funding development of the market.”

Similarly, he stated that BPA is, in fact, providing $25,000 to fund the Pathways Initiative but declined to make a public commitment before ensuring that the funding is “compatible with a different, much larger grant from the U.S. Department of Energy.”

Still, EDAM’s independence hinges on support from the California Legislature. Hairston noted, “It will be important to see if the Legislature will approve a full scope of independence.”

BPA will release a draft policy letter in March 2025 that will provide greater clarification on the agency’s final decision, according to the letter.

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NERC Submits Energy Assurance Standards to FERC

NERC has submitted two new reliability standards for FERC approval, both aimed at addressing the risks arising when energy resources with inconsistent output are unable to meet the demands of the grid and maintain reliability. 

The ERO filed BAL-007-1 (Energy reliability assessments) and TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) on Jan. 6, asking that the commission approve both standards, along with proposed definitions for the terms “energy reliability assessment” (ERA) and “near-term ERA.” If approved, the definitions will be added to NERC’s Glossary of Terms. 

NERC’s Board of Trustees approved the standards, their implementation plans and the definitions at its most recent open meeting Dec. 10, along with several other proposed standards. (See “Standards Approved for FERC Submission,” NERC Board of Trustees Briefs: Dec. 10, 2024.) 

BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources) and received segment-weighted approval votes of 81.53% and 92.77%, respectively, in a formal ballot round that ended Nov. 4. (See “Approved Standard to be Updated,” NERC Standards Committee Briefs: Nov. 13, 2024.) 

NERC began the project in response to the grid’s ongoing transition from traditional inertial generation resources to weather-dependent resources like solar and wind. The ERO said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources, which may suffer inconsistent output associated with the weather and volatility in load. 

It called BAL-007-1 “a step in transitioning to energy-based planning methods in the operations planning time horizon [by helping] achieve a level of consistency across the industry” in terms of planning methods and strategies. The standard would require BAs to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. 

Near-term ERAs required by the standard must include assessments of the resources necessary to serve demand while also providing operating reserves for the grid. An assessment period would begin no more than two days after the operating day, and cover between five days and six weeks. 

BAs would be able to specify the frequency of their ERAs. By default, all time periods must be covered, so that, for example, a near-term ERA that covers two weeks may be performed every two weeks or every other week, but not every three weeks, because this would leave a gap in coverage. This requirement may be waived if the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low. 

A BA could perform the near-term ERA for its work area alone or jointly with other BAs for all their areas together. NERC said this arrangement was meant to mirror partnerships that already exist between BAs for “other operations or planning activities and real-time operations.” 

The standard also lists minimum elements that BAs must include in near-term ERAs: 

    • forecast or assumed demand profiles; 
    • resource capabilities and operational limitations (including fuel supply); 
    • energy transfers with other BAs; and 
    • known grid transmission constraints that limit the ability of generation to deliver their output to load. 

The proposed changes in TPL-003-7 are relatively minor. NERC said they will “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.” 

As set forth in the proposed implementation plan, the ERO asked that FERC make TOP-003-7 effective the first day of the first calendar quarter that is 18 calendar months after the effective date of its order approving the standard, with BAL-007-1 to take effect six months later. This arrangement would provide six months for entities to collect the data needed for near-term ERAs and provide it to BAs before they are required to perform the assessments. 

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Delaware, US Wind Finalize $100M+ in Community Benefits

Delaware has finalized a benefit agreement with US Wind for allowing the developer to use a state park to run export cables from the offshore wind farms it hopes to build.

State officials announced Jan. 6 that the deal will be worth more than $128 million to the state and its residents over more than 20 years.

US Wind received key federal approvals in late 2024 for construction and operation of up to 2.2 GW of wind power generation capacity in three phases.

The developer has secured offshore renewable energy certificates from the state of Maryland for the first two phases, known as MarWin and Momentum Wind, rated at 1.1 GW combined.

US Wind’s 80,000-acre lease area sits at the latitude of northern Maryland, but the plan is to run the export cables farther north, to southern Delaware. US Wind wants to route them beneath a parking lot at the Delaware Seashore State Park, then under the Indian River Bay on their way to Delmarva Power and Light’s Indian River Substation in Dagsboro, Del.

The developer announced Dec. 10 that the state had approved three key permits to do this.

The Jan. 6 announcement by the state Department of Natural Resources and Environmental Control (DNREC) centered on compensation to Delaware for allowing it. The agreements include:

    • 150,000 renewable energy credits per year — estimated lifetime value of $76 million — transferred from US Wind to Delaware utilities to help them meet clean energy requirements, thereby lowering customer costs.
    • $40 million from US Wind over 20 years for coastal waterway dredging, clean energy workforce training, scholarships and resiliency and capital projects at state parks.
    • $12 million-plus in 25 years of lease payments to Delaware State Parks for the underground cables.

DNREC said indirect benefits to the state and its people over 20 years include up to $253 million in reduced electric costs for consumers and more than $200 million in transmission system upgrades.

Maryland is an enthusiastic supporter of offshore wind and has set an 8.5-GW goal for itself. But it has encountered the same headwinds as other states in trying to meet that goal. Ørsted has placed its Skipjack Wind plan on indefinite hold amid challenging economics, and Maryland has allowed US Wind to seek higher compensation so it does not succumb to those economic challenges.

There also is the inauguration in two weeks of a president who has been openly hostile to offshore wind development, which may complicate or delay development of MarWin and Momentum. Donald Trump doubled down on his campaign trail rhetoric Jan. 7, telling reporters he wants zero wind turbines erected during his administration.

Closer to home, there is some popular opposition to wind development off the Delmarva shoreline.

Local media have reported that Sussex County denied a US Wind subsidiary the permit it needs to build a substation, that Ocean City is suing to reverse federal approval of the project, and that opponents have appealed DNREC’s approval of the export line’s placement.

But Delaware focused on the positive in its Jan. 6 announcement. DNREC Secretary Shawn M. Garvin said in the news release:

“The DNREC State Energy Office’s recently released State Energy Plan emphasizes the need for offshore wind development in order to reach our emissions reduction goals, and the need to consider partnerships with other states and wind project developers to reduce costs. Additionally, the funding for dredging, resiliency and parks projects and workforce training will provide needed resources to protect and preserve Delaware’s natural resources for decades to come.”

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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.