A new policy paper from the Acadia Center and the Clean Air Task Force (CATF) emphasizes the importance of community engagement to enabling the wide-scale deployment of clean energy infrastructure over the next two decades.
“For New England to build out its infrastructure at the speed and scale needed to unlock a local energy transition, it will take buy-in, acceptance and trust from the communities that will host these clean energy resources,” the climate advocacy nonprofits wrote in the report, published Nov. 25.
The paper includes a quantitative literature review of five recent studies on decarbonization in the region, which, on average, indicate New England’s peak load will grow to 55 GW by 2050, compared with the 2024 peak load of 24,310 MW. This figure is in line with ISO-NE’s projection of a 57-GW winter evening peak in 2050.
To meet the growing demand, the review found the region will need to add “up to 5 GW of new clean energy capacity per year” for the next 20 years, assuming the region’s existing nuclear plants remain online. The studies estimated on average that 84% of generation in 2050 will come from renewables.
“The highest order recommendation is that the region must adopt a diverse, clean energy portfolio approach to achieve decarbonization goals while keeping the lights on and heat pumps running,” the nonprofits said, adding that this portfolio should include a mix of renewables, clean firm generation, interregional transmission, demand flexibility, energy efficiency and storage.
The organizations emphasized how energy efficiency and demand flexibility could help significantly reduce the peak, with the studies estimating that flexibility could reduce the 2050 peak by about 7%. This peak reduction could save the region billions in transmission costs alone; ISO-NE found in its 2050 Transmission Study that a 10% reduction in peak load could reduce the overall transmission buildout cost by about a third.
The nonprofits noted that energy efficiency and building retrofits were not modeled in detail in the studies and said more research is needed to quantify the full potential of both efficiency and demand flexibility.
“Increased modeling focus on the cost-effective potential of building envelope improvements to reduce overall space heating demand could reveal lower levels of generation buildout than currently found by these studies,” the groups wrote.
“Energy efficiency can and should be deployed as a competitive resource, able to be procured and acquired by the MWh or MW just as states and the region currently procure generation resources,” the groups added, noting that the prices of efficiency procurements likely would be cost-competitive with solicitations of large-scale renewables.
Community Buy-in Needed
Efficiency, demand flexibility, advanced transmission technologies, repowering existing renewable sites and strategies like agrivoltaics can help reduce the overall infrastructure footprint, but any decarbonization scenario will still require large amounts of new infrastructure, the report said.
To enable the construction of this infrastructure, developers must do a better job building community buy-in for their projects, incorporating feedback into project design, and providing tangible local benefits, the nonprofits wrote.
The report features case studies of several high-profile projects from recent years, including the canceled Aroostook Renewable Gateway and Twin States Clean Energy Link projects, along with Eversource Energy’s substation in East Boston — which is expected to come in service in 2025, 11 years after it was initially proposed.
“Levels of community support or opposition are key factors in a project’s success or failure,” the report said. “High profile project failures and stories of bad actors spread between communities and stoke opposition.”
The organizations added that community benefit agreements alone are not enough to prevent opposition and said “the process of negotiating and implementing community benefits programs is as important as the benefits themselves.”
“Development of a community benefit should occur through an early, inclusive, community-led process that not only informs the structure of community benefits program, but also incorporates community input into the design of the project itself,” the report said, adding that benefit plans should include accountability measures to ensure promises are met.
Community opposition also can be amplified by fossil fuel companies and incumbent power producers, the groups said, referencing the campaign to stop the New England Clean Energy Connect Pipeline and the challenges to the Vineyard Wind project funded by fossil fuel groups. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.)
“Those who have benefited from the region’s widespread reliance on fossil fuel infrastructure are reluctant to accept, and often in opposition to, shifting the resource mix [toward] clean energy generation,” the groups wrote. “Incumbent power generators have interfered in infrastructure development in numerous instances, particularly around transmission that would bring new clean energy supply into the market.”
The Balancing Authority of Northern California (BANC) on Nov. 25 became the third entity to formally join CAISO’s Extended Day-Ahead Market (EDAM), following PacifiCorp and Portland General Electric (PGE).
“BANC is pleased to execute the EDAM implementation agreement with the ISO,” BANC General Manager Jim Shetler said in a press release, adding that CAISO’s Western Energy Imbalance Market (WEIM) “has brought BANC and its members reliability, economic and environmental benefits.”
“EDAM participation is viewed as the next logical step to expand on those benefits. We look forward to working with the ISO to achieve a spring 2027 go-live date,” Shetler said.
BANC is a joint powers authority consisting of six utilities: Sacramento Municipal Utility District (SMUD), Modesto Irrigation District, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake. It has been a WEIM member since 2019.
In 2023, BANC was one of the first entities — along with its largest member, SMUD — to announce its intent to join the EDAM, after PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.)
The formal commitment comes a month after the Western Area Power Administration (WAPA) said its Sierra Nevada (SN) region would pursue “final negotiations” to join the EDAM, clearing the way for BANC to formally join. (See WAPA Sierra Nevada Region to Advance with EDAM.)
“We are excited to welcome BANC as the first public power balancing authority to formally commit to join EDAM,” CAISO CEO Elliot Mainzer said. “They have been a valued partner whose voice has been instrumental to the design of EDAM, and we look forward to having them join the market to deliver more benefits to their customers.”
Along with formal commitments from BANC, PacifiCorp and PGE, three other entities have signaled their interest in joining EDAM: Los Angeles Department of Water and Power, BHE Montana and PNM. An additional two entities, Idaho Power and NV Energy, have indicated they favor EDAM.
The Pathways Initiative’s “Step 1” plan, which elevates the Western Energy Markets Governing Body to become the “primary” authority over the WEIM/EDAM compared with the “joint” authority it currently shares with the ISO’s Board of Governors, will be triggered once EDAM commitments from non-ISO load reach 70% of ISO load. BANC’s participation means EDAM has achieved commitment from 53% of non-ISO load compared with ISO load.
BANC’s EDAM implementation agreement is slated to be filed with FERC in December.
SPP’s competing Markets+ offering on Nov. 25 won its first public commitments from four Arizona utilities, although the RTO is still awaiting FERC approval for the market’s tariff and no implementation agreements have been signed. (See 4 Arizona Utilities Commit to Joining Markets+.)
Replying to two recent cybersecurity-related Notices of Proposed Rulemaking from FERC, NERC and the regional entities Nov. 22 expressed their support for the proposals while urging the commission to “consider the entirety of” the ERO Enterprise’s standards development process when setting their deadlines.
The NOPRs propose to expand the ERO’s recently introduced reliability standard requiring registered entities to implement internal network security monitoring (INSM) at some grid-connected cyber systems (RM24-7) and to address perceived gaps in the standards concerning supply chain risk management (RM24-4). The commission issued both NOPRs at its monthly open meeting Sept. 19. (See FERC Proposes Further Cybersecurity Measures.)
Clarity Requested on INSM Expansion
The INSM proposal builds on CIP-015-1 (Cybersecurity — INSM), which FERC proposed to approve in the same NOPR. The standard requires utilities to implement INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity.
While FERC said the standard would advance grid reliability, in its current form, it is “not … fully responsive to the commission’s directive” to implement INSM. In particular, the commission worried that attackers may be able to compromise systems external to an entity’s electronic security perimeter (ESP) and use that control to establish access within the perimeter as a trusted connection.
It proposed directing NERC to modify the standard to include electronic access control and monitoring systems (EACMS) and physical access control systems (PACS) in the list of those requiring INSM, which it said would protect “all trust zones of the CIP-networked environment.”
In its response, NERC first called on the commission to approve CIP-015-1 “as expeditiously as possible,” saying the standard would “improve the probability of detecting anomalous or unauthorized network activity” and help utilities respond to cyberattacks. But, the ERO continued, FERC needs to provide additional clarity on what it means by the term “CIP-networked environment.”
Although NERC acknowledged that FERC said in the NOPR that the term includes “all assets and systems to which the CIP [critical infrastructure protection] standards apply and [that] may be the targets of attacks,” the ERO pointed out that the term is still not explicitly defined in the proposal.
“To facilitate an expeditious development process, it would be beneficial if the commission clarifies in a final rule the expected scope of any internal network security monitoring revisions,” NERC said. “For example, in extending the CIP-015-1 protections to EACMS and PACS, would the term ‘CIP-networked environment’ be restricted to east-west communications between EACMS and PACS outside of the ESP? Similarly, would the communications between PACS and controllers and communications to and from EACMS used solely for electronic access monitoring be included?”
NERC also suggested that FERC give the ERO at least 12 months to complete the proposed revisions, in light of the ERO’s growing standards development workload. NERC pointed out that it is already resolving 82 outstanding FERC directives through the standards development process, and its seven “high priority” projects alone are expected to take more than 10,000 total drafting team hours to complete by the end of 2025.
Noting that FERC proposed to require that the CIP-015-1 revisions be submitted within 12 months of the final rule, NERC urged the commission to give it enough time to “facilitate additional development options,” including a technical conference, while also allowing the ERO to “balance limited resources between competing high priority projects.”
ERO Supports Supply Chain Proposal
In the second NOPR issued Sept. 19, FERC indicated its intent to direct NERC to develop new or modified standards regarding evaluation of vendors and equipment to identify supply chain risks, along with processes to validate the accuracy of information received from vendors during procurement and track supply chain risks.
The commission said it felt moved to act because of “multiple gaps” in NERC’s existing supply chain risk management (SCRM) standards:
FERC said the standards do not specify when and how entities should identify and assess supply chain risks, and do not require entities to respond to supply chain risks through their SCRM plans.
In their response, NERC and the REs said they appreciate FERC for recognizing the work they have done so far to advance SCRM, including their efforts to revise CIP-013-2 (which were cut short when FERC announced it would be addressing SCRM at the September meeting).
They said they support the proposed revisions, including adding protected cyber assets (defined by NERC as “cyber assets connected … within or on an [ESP] that is not part of the highest impact … cyber system within the same [ESP]”) as applicable assets within supply chain requirements. However, as with the other NOPR, the ERO Enterprise reminded the commission of its standard development workload and the other deadlines to which it is subject.
The organizations also asked FERC to consider the relationship between the different standards. Some standards refer to others, and revisions to CIP-005-7, CIP-010-4 and CIP-013-2 could impact other ongoing standards development projects. For example, earlier in 2024, NERC filed a suite of proposed changes to nearly all of the CIP standards, including the three supply chain standards, which might affect the team tasked with carrying out FERC’s order. (See NERC Sends Virtualization Standards to FERC.)
NERC and the REs requested that FERC “consider no less time than proposed in the NOPR” — 12 months — to both accommodate the busy standards development pipeline and “provide the standards drafting team certainty on the version of CIP reliability standards to revise.”
Solar developers are urging the New Jersey Board of Public Utilities to extend the completion timelines in the agency’s proposed storage development plan, saying 550 days to complete a project and secure connection through PJM is too short.
The board’s draft proposal requires grid supply or distributed projects approved under the program to be commercially operating within 550 days of getting the agency award. If they are not, “the capacity they reserved would be returned to the market” and be available for other projects, the proposal says.
The timeline was the most salient concern at a Nov. 20 hearing, in which other speakers — while generally supporting the proposal — called for the BPU to address a range of issues, among them accelerating the start of the program segment focused on distributed storage and strengthening it to make it more attractive to developers.
The proposal, the New Jersey Storage Incentive Program (NJ SIP), sets out the guidelines for two sectors: a program for behind-the-meter, distributed projects that is expected to launch in 2026 and one for in-front-of-the-meter projects, including grid supply projects, that will begin in early 2025.
At least six of the more than two dozen speakers said they believe the project completion deadline — known as a maturity requirement — is too restrictive.
Dan Watson, director of development at Jupiter Power, a large-scale energy storage developer, said construction alone can take three years on a large project.
“It can be a long time with the PJM related upgrades as well,” he said. “So, the 550-day timeline is in obvious need of correction and consideration for larger projects.”
Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said a grid supply project in front of the meter would “be applying as a wholesale generator in order to do a front-of-the-meter project,” and the current proposed timeline would be tough to meet.
“That’s a process that could take as long as two years or more,” he said. “I know you want to get started on that program in 2025. But it’s unlikely that we can even get approvals until 2027.”
PJM is working through a major backlog of resources and is not accepting any new project requests until 2026.
The proposal says the intent of the requirements “is to eliminate projects that cannot be expected to reach commercial operation within a reasonable time frame.” The proposal explains that a project is considered to have reached commercial operation if “it is fully constructed and has completed the full interconnection process, either at PJM or with a New Jersey jurisdictional [electric delivery company], including construction of any required interconnection upgrades.”
A BPU representative at the meeting said the BPU’s consultant on the project suggested the 550-day timeline. He added that several speakers expressing concern about the requirements “gets our attention,” and the BPU staff would consider the issue.
Launch Date Controversy
The NJ SIP proposal is a revised version of a draft proposal first released in September 2022, with changes made in response to stakeholder input. The state aims to install 2,000 MW of total capacity by 2030, but progress has been slow. A BPU spokesperson said the state currently has 560 MW of installed storage, but that capacity will not be counted toward the 2,000-MW goal.
Several speakers said there is significant interest in developing storage in the state. Diane Cherry, deputy director of the Mid-Atlantic Renewable Energy Coalition, said there are 3,700 MW of storage projects in the PJM queue. Noting the state’s 2,000-MW goal, she urged the BPU to focus on grid-supply project incentives and said, “We can easily meet and exceed this goal with the appropriate regulatory direction.”
Joshua Lewin, president of Helios Solar Energy of Somerville, N.J., encouraged the board to consider launching both the distributed and grid supply segments in 2025, rather than delay the distributed project launch by a year — an opinion also voiced by other speakers.
“This continued delay in the program rollout is unhelpful in gaining customer willingness to enter a new and unfamiliar market,” he said.
The revised NJ SIP includes a competitive solicitation to determine the incentive level for grid supply projects, which was not in the original plan. Also new is an option under which the BPU will accept applications from solar-plus-storage projects, rather than standalone storage projects. That will allow the program to accept projects that are not eligible to receive storage incentives from the Competitive Solar Incentive part of the Successor Solar Incentive program, which encompasses solar-plus-storage projects. (See NJ BPU Updates Proposal for Storage Incentives.)
The revised proposal also makes the bid-participation fee of $1,000/MW refundable to unsuccessful bidders, instead of nonrefundable. BPU said the shift stems from the addition to the plan of a “pre-development security” of up to $100,000/MW, to be paid upon application approval.
The security is designed to ensure the project is carried out as planned, allowing the BPU to impose penalties that will be deducted from the security if the project misses the Planned Commercial Operation Date or the Guaranteed Commercial Operation Date.
The storage proposal also has deferred implementation of a distributed pay-for-performance incentive on projects to give utilities time to develop the mechanism to calculate it.
Prioritizing Segments
Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, urged the BPU to focus the program resources on distributed storage rather than grid-scale storage projects. He said the association’s recent member survey showed many already are engaged in the sector.
“There’s a lot of development going on anywhere from less than 10 kWh to tens of megawatt-hours in the behind-the-meter storage field,” he said. One reason, he said, is that “behind-the-meter revenue is substantially more than the grid supply revenue.”
“Behind-the-meter storage is going to be for the foreseeable future more economic, and that means long term a better ability to reduce the incentives from the program and save ratepayers money,” he said. Other speakers said distributed projects, because they are smaller, may get up and running and contribute to the state’s need for storage more quickly.
Addressing the ratepayer impact, Megan Lupo, assistant deputy ratepayer advocate for the New Jersey Division of Rate Counsel, took issue with a new element in the proposal that directs the BPU to pay developers or owners the full project incentive upfront, rather than over 10 to 15 years.
She said the board staff concluded the new system would reduce the level of risk and so bolster program incentives.
“However, it is not clear that any additional incentives are needed for New Jersey to achieve its statewide goals,” she said. “An increase in incentives should be supported by evidence that proves the current incentives are insufficient to meet statewide targets. If not, New Jersey risks over-incentivizing energy storage.”
Lupo also expressed concern about making the fees refundable.
“This change would risk making the bidding process less meaningful and may cause an increase in the number of bids that are speculative in nature,” she said, adding that $1,000/MWh is low compared to other states.
“There is no reason to believe these current nonrefundable fees are overly burdensome to bidders,” she said.
With less than two months until President-elect Donald Trump takes office, the Department of Energy’s Loan Programs Office on Nov. 25 announced three conditional loans totaling more than $11 billion, to be used to build interregional transmission, an electric vehicle factory and virtual power plants.
Invenergy’s Grain Belt Express, an interregional high-voltage direct current line, has received a conditional loan of $4.9 billion to help finance Phase 1 of the project, a 578-mile, 2,500-MW line running from Ford County, Kansas, to Callaway County, Missouri, according to the LPO announcement.
The second phase of the project, from Missouri to Illinois, eventually will take the HVDC line to 800 miles and connect SPP, Associated Electric Cooperative, MISO and PJM. The LPO announcement notes that DOE’s National Transmission Needs Study has estimated that interregional transfer capabilities between SPP and MISO might need to increase tenfold by 2035 to meet growing power demand.
EV maker Rivian is slated for up to $6.57 billion for the development and construction of a new plant east of Atlanta. The company plans to build out the facility in two phases, with production of its R2 and R3 SUVs beginning in 2028 and eventually ramping up to 400,000 vehicles per year, according to a Nov. 25 press release.
If finalized, the Rivian loan would be the first made under LPO’s Advanced Technology Vehicles Manufacturing (ATVM) Loan Program to manufacture EVs in the U.S., as opposed to EV components, LPO said.
A third conditional loan, for $289.7 million, will go to Sunwealth, a commercial solar developer, which will use the money to install up to 1,000 solar and storage systems across as many as 27 states. The projects will include installations on commercial and multifamily buildings, as well as community solar facilities.
Partnering with SYSO, a developer of distributed energy resources management systems, Sunwealth intends to aggregate the systems as a virtual power plant. Estimated capacity of the systems could total up to 168 MW of solar and 16.8 MW and 33.6 MWh of battery energy storage, according to LPO.
The announcements of the conditional loans signal the start of contract negotiations between LPO and the potential recipients to finalize the awards. Companies must “satisfy certain technical, legal, environmental and financial conditions before [LPO] enters into definitive financing documents and funds the loan,” the announcements all say.
These negotiations often take months, which could mean uncertainty for the awardees. Prior to his election, Trump pledged to claw back any unspent dollars from the Inflation Reduction Act, which added billions to the funds available to LPO. Some analysts have predicted a Day 1 executive order halting any further distribution of IRA funds.
In response to questions from RTO Insider, an LPO spokesperson did not comment on whether the office would be able to finalize the contracts for these three conditional loans before Trump takes office, focusing instead on the office’s role as a “bridge to bankability” for a broad range of greenhouse gas-reducing technologies.
Since President Joe Biden took office in 2021, LPO has announced 31 deals totaling approximately $47.72 billion in project investment, including 13 projects with finalized contracts for $13.18 billion in federal support. Contracts for 18 projects totaling $34.54 billion are pending, according to the spokesperson.
“Utilizing funding provided by Congress, LPO has accomplished tremendous progress in a short amount of time on bipartisan priorities including advanced nuclear, geothermal, advanced fossil energy and critical minerals,” the spokesperson wrote in an email. “As a result, there is steel in the ground and job openings at new or expanded facilities around the country.
“It would be irresponsible for any government to turn its back on private-sector partners, states and communities that are benefiting from lower energy costs and new economic opportunities spurred by LPO’s investments.”
Navigating Uncertainty
Both Invenergy and Rivian welcomed the LPO announcements, while still navigating ongoing uncertainties about their respective projects.
In an emailed statement, Shashank Sane, executive vice president and head of transmission at Invenergy, said, “We are pleased to see LPO’s evaluation validate the findings of the Kansas and Missouri public utility commissions, both of which have long affirmed our project is key to improving grid affordability and reliability across the Heartland.”
The first phase of the project has earned successive approvals from the Kansas Corporation Commission, originally in 2019 and again in 2023 to increase capacity for power delivery on the line, according to the project website. The Missouri Public Service Commission issued similar approvals in 2019 and 2022.
However, Invenergy has run up against interconnection delays in MISO, which has given the project a 2030 interconnection date, versus the project’s original target of a 2027 in-service date. In February 2024, FERC approved an interconnection agreement with the 2030 date.
Rivian founder and CEO RJ Scaringe said the LPO’s loan, if finalized, “would enable Rivian to more aggressively scale our U.S. manufacturing footprint. … A robust ecosystem of U.S. companies developing and manufacturing EVs is critical for the U.S. to maintain its long-term leadership in transportation.”
Rivian suspended work on the new plant in Georgia in March, shifting production of its R2 SUV to its plant in Illinois, a decision saving the company $2.25 billion, according to a press release.
The company has not specified when it will resume work on the plant, but according to a spokesperson, “Georgia will provide the volume of production essential for us to enter new markets, including international ones. We expect to start construction to meet our stated goal of start of production in 2028.”
Four Arizona utilities announced their plans to join SPP’s Markets+ day-ahead market, a significant win for SPP after a string of victories for CAISO’s competing Extended Day-Ahead Market (EDAM).
Arizona Public Service (APS), Salt River Project (SRP), Tucson Electric Power (TEP) and UniSource Energy Services made the announcement Nov. 25.
Markets+ is expected to save the utilities nearly $100 million while enhancing reliability and supporting the addition of renewable resources to the grid, the utilities said in a joint release.
The utilities said they plan to begin Markets+ participation as soon as 2027.
“Together with our neighboring utilities, APS plans to join Markets+ to efficiently deliver energy and bolster the resilience of our shared energy grid in Arizona and across the region,” Brian Cole, APS vice president of resource management, said in a statement.
When asked about the reasons for choosing Markets+ rather than CAISO’s EDAM, an SRP spokesperson said the primary drivers are governance and resource adequacy.
The Markets+ governance structure promotes independence, transparency, inclusivity and stakeholder-driven decision-making, the spokesperson said.
And Markets+ will adhere to a single, shared resource adequacy program — the Western Resource Adequacy Program — providing a consistent method to make sure enough resources are available to reliably serve load across the Markets+ footprint.
“It also ensures that all market participants contribute fairly to the reliability of the market footprint, preventing any participants from systemically leaning on others,” the SRP spokesperson said.
SRP expects a critical mass of entities joining Markets+ in spring 2027, and SRP will sign an implementation agreement before the market goes live.
Tariff Decision Pending
The announcement comes as SPP awaits FERC’s decision on the Markets+ tariff, which initially was filed in March. FERC issued a deficiency letter in July identifying 16 problems in the tariff. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)
SPP filed a response to the letter in September, addressing each issue and asking FERC to issue an order by Nov. 20.
But FERC isn’t required to abide by that request and will take “as much time as they need,” an SPP spokesperson told RTO Insider. SPP said previously it’s confident it can address concerns the deficiency letter raised.
In contrast, CAISO’s EDAM already has received FERC approval.
A TEP spokesperson said the company fully expects FERC to approve the Markets+ tariff, while acknowledging the approval can be an “iterative process,” a comment echoed by SRP.
“We will continue to work with FERC and SPP throughout the process in demonstrating the value this direction will bring to our customers,” the TEP spokesperson said.
FERC approval of the tariff will mark the start of a second phase of Markets+ development.
“SPP thanks all Markets+ stakeholders for their engagement and collaboration in phase one development and looks forward to their continued involvement,” Antoine Lucas, SPP vice president of markets, said in a statement provided to RTO Insider. “We eagerly anticipate receiving signed phase two commitments by the end of the year so we can continue to work together to build a market that provides benefits for all western entities.”
Footprints Taking Shape
The Arizona utilities’ announcement of their Markets+ decision is the latest step in the evolution of two day-ahead market footprints in the West. In addition to the Arizona announcement, Bonneville Power Administration has expressed a “leaning” toward Markets+ over CAISO’s EDAM. BPA is waiting for FERC’s ruling on the Markets+ tariff before deciding. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.)
Although Powerex has not yet made a formal commitment to a day-ahead market, it has clearly signaled an intention to join Markets+ and to not join EDAM.
The Arizona announcement “is a clear indication of the value that many utilities are seeing in the Markets+ day-ahead market option,” Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), said in an email to RTO Insider.
The Portland-based PPC, a trade group representing the extensive network of Northwest publicly owned utilities that buy low-cost power from the Bonneville Power Administration, has been a consistent advocate of BPA choosing Markets+ over CAISO’s EDAM. (See Northwest Public Power Group Endorses Markets+ over EDAM.)
“As a participant in the development of Markets+, PPC has appreciated the collaboration we have had with these Arizona utilities and the shared goals we have for a well-designed, well-governed day ahead market option,” Tenney Denison said.
Meanwhile, EDAM scored its latest win this month with Public Service Company of New Mexico’s announcement of its plans to join the CAISO market. (See PNM Picks CAISO’s EDAM.)
PacifiCorp, Portland General Electric and Balancing Authority of Northern California have signed EDAM implementation agreements with CAISO and the list of entities expected to join EDAM has grown to include NV Energy, Idaho Power and Los Angeles Department of Water and Power.
In October, the Western Area Power Administration’s Desert Southwest (DSW) Region said it would cooperate with Arizona G&T Cooperatives on a study examining the potential benefits of DSW joining EDAM. DSW this year withdrew from the second phase of developing Markets+ after determining it would realize few benefits from participating in that market. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)
After NV Energy announced its intent in May to join EDAM, Advanced Energy United issued a statement encouraging other entities, especially those in the Southwest, to join EDAM. The industry association said EDAM was becoming “the most viable day-ahead market.”
Brian Turner, who leads Advanced Energy United’s regulatory engagement in the West, said AEU is pleased that Arizona utilities are “embracing broader energy markets,” which have the potential to bring customer benefits including greater reliability and affordability.
But Turner said the Arizona announcement is “bittersweet,” as having two Western day-ahead markets will create seams and market inefficiencies.
As the market footprints are now developing, Markets+ could end up with a “big fat seam” in Northwest-Southwest trade caused by NV Energy and California entities joining EDAM, Turner said in an interview.
And the Arizona utilities are giving up known benefits of their participation in CAISO’s Western Energy Imbalance Market (WEIM) in exchange for unknown potential benefits of Markets+, he added.
But how the Western day-ahead markets ultimately take shape remains to be seen.
Members Endorse 2 Changes to Transmission Planning
ERCOT stakeholders approved a pair of protocol changes related to transmission planning as the Texas grid operator continues to grapple with connecting incoming load to its system.
During the Technical Advisory Committee’s Nov. 20 meeting, members approved NPRR1247, which uses a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. They also approved NPRR1180 and a related change to the Planning Guide (PGRR107) that incorporates a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecasted load growth and additional load seeking interconnection.
Several generators and retailers opposed the first protocol change, noting that congestion costs can be hedged but transmission costs can’t.
“We think basing decisions on that is probably discounting a significant value that accrues to loads,” Luminant’s Ned Bonskowski said.
The NPRR was brought forward by ERCOT staff after collaborating with the Public Utility Commission. The ISO retained Energy and Environmental Economics (E3) to identify a set of viable options and provide recommendations for the most suitable congestion cost savings test. E3 presented its work in a March 2024 analysis, recommending a system-wide energy cost reduction test as the most suitable for ERCOT.
While staff approved E3’s recommendations, Luminant said the proposed congestion cost savings test could increase costs for ratepayers when competitive market solutions could serve load less expensively. The generator suggested applying a .25 multiplier factor to the calculated system-wide consumer energy cost reduction before using it to determine a project’s economic benefits.
“We think this may be a good compromise,” Bonskowski said. “If there’s a need to move forward on something today, we certainly would also support tabling” to give stakeholders more time to “make sure that we get this right before sending it up to the board.”
The vote to table NPRR1247 fell short, 11-17, with one abstention.
Mark Bruce, speaking for Pattern Energy, said his client is concerned about an overall lack of transparency and the need for further vetting. He said Luminant lacked backing data in its comments and urged stakeholders to revisit the matter with a change to the Planning Guide to further prevent downstream effects.
“I know there’s been some pressure from above to deliver something to the board on this at their next meeting,” Bruce said. “My client’s been engaged from the get-go, from its first showing as a draft before it was even filed. We’ve been trying to understand and perfect this very important revision request.”
TAC eventually approved the measure 25-3, with one abstention. Luminant, Calpine and Shell North America all opposed the motion.
The committee approved NPRR1180 25-0, with four abstentions, two from consumer interests.
The Office of Public Utility Counsel’s Nabaraj Pokharel said he supported the rule’s legislative intent but stressed the importance of ensuring load projections used for planning “are as accurate as possible.”
“There is a risk of unintended consequences, particularly if load studies are not thorough or accurate,” he said. “While building transmission to meet actual load is necessary, [it] could result in unnecessary cost that would ultimately be borne by residential consumers.”
To remedy that concern, Mark Dreyfus, speaking for a coalition of cities, suggested approving the protocol change and filing a follow-up revision request that drills down into the load-projection’s validation process.
“There’s a lot of projects waiting to have this process in place and we need to get moving on those projects,” he said.
Texas Competitive Power Advocates Executive Director Michele Richmond said several meetings with Oncor and other wires companies have resulted in a draft proposal for another NPRR that would address the process’ transparency and standardization.
“I think we are very comfortable with moving this forward, given that commitment and the really good discussions that we have been having,” Richmond said.
Large Loads Need a Segment Home
TAC discussed with staff potential changes to the committee’s segment makeup, driven by the growing influence of data centers and cryptocurrency miners that don’t fit neatly into either the industrial consumer or large commercial segments.
ERCOT membership has risen from 257 members in 2021 to 356 this year, mostly because of large flexible loads. Staff has asked entities with large loads to register in the industrial segment when making their membership applications for 2025.
The grid operator’s seven segments are used to fill out the 30-person TAC. Any changes to the representation would require an amendment to the bylaws and PUC approval.
“Things have changed a lot,” Engie’s Bob Helton said, alluding to a TAC segmentation that has been static since 2014. “Every time we talk about this, we have to be careful of balance. Anything we do is going to be a long, drawn-out deal to make sure that that balance remains in place and that no segment or group has a heavier weight than any other one in trying to approve things.”
Staff said ERCOT now has just over 62 GW of large loads in its interconnection queue. It has added another gig of new standalone and co-located projects since October.
West Texas Project Endorsed
TAC members endorsed ERCOT’s recommended $202.2 million Oncor project that addresses reliability issues in West Texas, placing it on the combination ballot.
The project stems from the 2019 Delaware Basin Load Integration Study. The region has significant oil and natural gas load and ERCOT’s highest peak demand growth rate percentage in recent years.
The Regional Planning Group approved Oncor plans to upgrade an existing capacitor station, build 22 miles of double-circuit 345-kV lines, convert 41 miles of 138-kV lines to 345-kV, build 41 miles of new 138-kV lines, and install six 5000-A, 345-kV circuit breakers. The project is expected to be completed in 2027.
Because the project cost more than $100 million, making it a Tier 1 project, it must be approved by ERCOT’s Board of Directors.
Co-chair Martin to Step Away
The meeting was the last as TAC’s co-chair for Collin Martin, Oncor vice president of grid operations. Martin told his fellow members he is stepping away “partially” to focus on potential transmission projects in the Permian Basin.
“I appreciate everybody’s confidence in being able to be seated to this on the table,” he said. “It’s been a great year. I learned a lot.”
“I learned a lot from Collin,” said TAC Chair Caitlin Smith, with Jupiter Power. “He brought a wide range of knowledge to TAC leadership, and not just the engineering side. He knows a lot about the market side and the systems and everything. I think having him here to add his perspective has been very valuable.”
Fellow Oncor employee Martha Henson has been proposed as Martin’s replacement. Smith will continue as chair.
HDL Override Change Tabled
TAC again tabled a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. Members directed their Wholesale Market Subcommittee to provide remarks on the change back to the Protocol Revision Subcommittee before they take it up again in January.
The change was approved by TAC in June. However, the board remanded it back to TAC in October over the consumer segment’s concerns that the NPRR would reward overscheduling of power that cannot be delivered. Members of that segment say that will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions. (See “2025 AS Methodology OK’d,” ERCOT Board of Directors Briefs: Oct. 9-10, 2024.)
Reliant Energy Retail Services’ Bill Barnes said he has discussed this with Eric Goff, who represents residential consumers but was unable to attend the meeting, and floated a concept from their conversation. He said it acknowledges consumer concerns about a situation where HDL overrides become a “dominant component” of the market.
“We would be more dependent on these out-of-market payments. That’s not the goal of 1190. That’s not the goal for any of us,” he said.
Barnes said an annual settlement trigger, should ERCOT find itself in a situation where it hits a threshold amount of HDL payments, would lead to a review of the protocol’s language. That would tighten the contracts eligible for some participants, he said.
Members unanimously endorsed a combo ballot that included four NPRRs and related changes to the Planning Guide (PGRR) and Nodal Operating Guide (NOGRR) and an Other Binding Document request that will do the following if approved by ERCOT’s board:
NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system secure area to the public ERCOT website.
NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ERCOT ECEII information from the market information system secure area to the public ERCOT website. The change also conforms rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; for making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and for posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website.
NPRR1246, NOGRR268, OBDRR052, PGRR118: insert terminology associated with energy storage resources (ESRs) into the protocols, aligning the ESRs’ provisions and requirements with those for generation resources and controllable load resources. The change applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model).
NPRR1254: require resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies.
NERC’s recently submitted Interregional Transfer Capability Study (ITCS) is “a phenomenal first step,” according to participants in a webinar hosted by the American Council on Renewable Energy and Americans for a Clean Energy Grid — but there’s still much work ahead to address the U.S. grid’s mounting reliability challenges.
Speakers at the Nov. 25 webinar included former FERC Commissioner Allison Clements; Robert Taylor, vice president for transmission and new markets at Invenergy; Michael Goggin, vice president at Grid Strategies; and Cy McGeady, a fellow for energy security and climate change at the Center for Strategic and International Studies (CSIS). ACORE and ACEG hosted the forum to discuss the implications of the ITCS and potential future steps for FERC, Congress and other stakeholders.
The ERO worked with the regional entities and transmitting utilities for 18 months to develop the three-part report, which FERC will post for public comment. A final installment focused on transmission between the U.S. and Canada, and between Canada’s provinces, is planned to be released in early 2025.
In the ITCS, NERC recommended 35 GW of additional transfer capability across transmission planning regions in North America to strengthen grid reliability, including two new connections between ERCOT and neighboring regions. (See NERC Releases Final ITCS Draft Installments.) The report’s authors emphasized the analysis did not account for economic issues and cost-benefit analysis, and that even with the recommended additions it would not be possible to resolve all energy deficiencies due to chronic “wide-area resource shortages.”
In ACORE’s webinar, McGeady called the ITCS an “excellent starting point” and a “baseline” for future studies. Similarly, Goggin said NERC and its collaborators “did a great job in really tight time constraints and with the pretty narrow scope that Congress gave them.”
At the same time, attendees said the narrow scope meant that NERC ended up performing a conservative analysis. Goggin said the 35 GW recommendation represents “a floor, in my view, of what you should be thinking about in terms of an optimal transmission expansion.” He noted that FERC tasked the ERO only with identifying “prudent” transmission additions to improve reliability, which meant the study understandably did not take some important factors into consideration.
“Basically, it’s just keeping the lights on. It’s not looking at the opportunity to reduce consumer costs by giving them cheaper power,” Goggin said. “More importantly, even on the resource adequacy side, it’s not looking at how transmission can help you share generating capacity. … The NERC study did look at this, but they didn’t look at how you could economically save on building power plant capacity by tapping into” neighboring regions’ generation.
McGeady added that the figures NERC used to estimate demand were based on the ERO’s 2023 Long-Term Reliability Assessment. He said the projections in this year’s LTRA likely were to be “profoundly larger, like significantly upward revisions.” This means the ITCS’ recommendations could turn out to be even more conservative than Goggin and other panelists thought.
Moderator Elise Caplan of ACORE suggested these concerns could be taken up by respondents when FERC opens comments on the study, along with how to meet the additional unmet needs that NERC identified.
Asked what actions FERC could take to improve reliability through interregional transmission ties, Clements said she believes the commission can play a significant role. She called on FERC to take the lead on interregional planning and on the cost allocation process.
“I think if you’re really, genuinely trying to get to reliability at this moment in time, across the systems that constitute this nation’s electricity systems, we need to be looking at all the tools in the toolbox,” Clements said. “When it comes to reliability, there’s often a quick jump to say you can’t retire the uneconomic thermal units that want to retire. … I think it’s imperative on the commission to say what are the quick, easy, fast ways to do that.”
“I wasn’t a champion of transmission just because I think transmission is great. In fact, it would be a lot easier if we didn’t have to build it,” Clements added. “I’m a champion of transmission because it is a way to get to cost-effective reliability for customers.”
VALLEY FORGE, Pa. — Stakeholder opinions were sharply divided at the PJM Members Committee’s meeting Nov. 21 regarding RTO proposals to allow high capacity factor resources to be sped through the interconnection queue and revise aspects of the capacity market.
The Reliability Resource Initiative (RRI) would advance 50 interconnection requests to Transition Cycle 2 (TC2) — an interim group of queues established as part of PJM’s interconnection process overhaul that began in 2023 — in an effort to address a possible resource adequacy gap identified in the 2029/30 delivery year. The proposal would require tariff changes to be approved by the PJM Board of Managers and FERC. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.)
Presenting the RRI, PJM Director of Interconnection Planning Donnie Bielak said the proposal is being brought to address “unique circumstances” and would be a one-time measure to allow uprates and resources that can quickly come online to be expedited through the queue to address a reliability need.
If more than 50 projects are submitted, selection would be based on a scoring formula that awards up to 35 points to projects based on their unforced capacity (UCAP); 35 points for the viability of being in service by June 1, 2029, or sooner; 20 points for higher effective load-carrying capability ratings; and 10 points for site location. The only hard eligibility requirements would be that a project must have a UCAP above 10 MW and that they are not part of a project under FERC Order 1000’s State Agreement Approach.
Resources not already subject to the requirement that they participate in the capacity market would be compelled to offer for at least 10 delivery years. Bielak said developers would have the choice of accepting a must-offer requirement for a project they are truly certain can be rapidly brought to market or wait to be sorted into TC1.
TC2 was open to projects sorted into the AG2 and AH1 queues, the latter of which closed in September 2021. Studies on projects submitted after that date are not likely to initiate until 2026.
Responding to stakeholder questions regarding the scale of the impact the RRI could have on TC2 cost allocation, Bielak said PJM does not know which projects will be submitted, and there are hundreds of projects that dropped out of the interconnection process that could be resubmitted. Potential cost allocation impacts vary significantly depending on which projects are submitted and ultimately selected by PJM.
Criticisms and Alternatives
Several renewable developers objected to the proposal, arguing it would constitute queue jumping and disrupt network upgrade cost allocation for projects that have been waiting in the queue for years.
Rahul Kalaskar, AES senior director of regulatory affairs, offered an alternative from AES Clean Energy and REV Renewables to run TC2 and RRI projects in separate cycles. The RRI projects would be added to the separate cycle, which starts after Decision Point 2 of the TC2 cycle and runs all the studies in one condensed process. Doing so would keep the network upgrades for the TC2 and RRI projects in two different buckets.
Kalaskar said that if PJM’s RRI design were to proceed, transmission headroom could be consumed, increasing the costs assigned to TC2 projects and possibly causing some to drop out of the queue.
Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power, said his organization conditionally supports RRI if changes are made to the scoring weights to prioritize project size and viability; projects that would be part of fixed resource requirement (FRR) plans are excluded; and developers are prohibited from buying out of their obligations.
Tonja Wicks, vice president of regulatory affairs for Elevate Renewables, said “project viability” and the “in-service date” should account for at least half of the project weighting, as it gets to the core issue that PJM is trying to resolve with the RRI: getting capacity that has the most certainty to come online by a set date. Otherwise it risks selecting projects that promise to bring a large amount of power, but with no firm site control or demonstration that they can meet milestones.
Independent Market Monitor Joe Bowring said the RRI should be preserved as a permanent option that PJM can deploy when it identifies reliability needs that can be resolved by expediting new development. Because projects are being fast-tracked to resolve capacity needs, he said the 10-year must-offer requirement should be expanded to the lifespan of the asset.
Mike Cocco, senior director of RTO and regulatory affairs at Old Dominion Electric Cooperative, said data center loads in northern Virginia are accelerating rapidly, and the RRI is necessary to ensure PJM can continue to meet demand. He said ODEC intends to submit projects to be studied under the RRI, possibly including combustion turbine generators, and he encouraged PJM to consider how the milestone deadlines for RRI projects could conflict with timelines for air quality regulations and other requirements.
“We’re in a position to bring generation online with the timeline that you’re looking for,” he said.
Grant Glazer, MN8 Energy’s manager of regulatory and market affairs, highlighted that projects in TC2 will be studied under a new generation deliverability test, which he said could identify violations prompted by projects in TC1. The status quo rules would assign those network upgrades to TC2 clusters, increasing their cost allocations for up to two-thirds of projects in the cycle. Instead, he encouraged PJM to revise the Regional Transmission Expansion Plan to capture those upgrades.
SIS Eligibility
Along with the RRI proposal, the filing with FERC would include tariff revisions to expand eligibility for projects seeking surplus interconnection service (SIS) by striking language prohibiting projects that could impact the network upgrades for new service customers in the queue.
Stakeholders argue the language is overly prohibitive and prevents developers from co-locating thermal resources with renewables and storage.
Sarah Toth Kotwis, RMI senior associate, said SIS is the fastest process available for bringing new resources online. Storage co-locating with existing resources can come online within 2.5 years of receiving an interconnection agreement, about half the time for adding new generation.
Wicks said PJM stands alone among RTOs in studying open-loop batteries as discharging in light load cases and using those outcomes to determine whether projects would consume headroom that could be used by other queue projects.
“With short duration times for construction and energizing, batteries are the types of resources FERC’s SIS directive envisioned utilizing excess capacity — a.k.a. surplus — at existing facilities to meet resource shortfalls and enhance reliability,” Wicks said.
PJM CEO Manu Asthana said RTO staff are open to revisiting the light load case test for storage, but that needs to be a discussion in the stakeholder process to ensure there are no unintended consequences. The tariff changes would remove barriers to allow that conversation to proceed.
Asthana said his read on stakeholder impressions on the proposed SIS changes is that PJM is on the cusp of resolving their core concerns about the service. He said PJM is taking that feedback and plans to continue pursuing changes.
“The door is not closed: We want to hear how we can make that work,” he said.
Bruce Grabow — a partner in Sheppard, Mullin, Richter & Hampton — urged PJM to take more time to vet the proposal through the stakeholder process, noting that stakeholders had only a few minutes to make their comments during the meeting, with some rushing to include all of their arguments. That is not how the stakeholder process is supposed to occur, he said.
Because of the lack of discussion, along with his assertion that PJM still had not provided data to stakeholders supporting the need for expedition, the RTO risks protests at FERC and in court, Grabow argued. He asked questions about the weighting system PJM intended to apply to determine which new generation projects would be winners and losers and whether the scoring means would be transparent; when PJM did not provide further detail, Grabow argued that meant the criteria would be subjectively applied, which does not comport with FERC standards of transparency, non-discrimination and preference.
Asthana said there is a need for as many TC2 projects as possible — ideally all of them — to be interconnected. He encouraged members to submit written comments by email, with directions provided in a communication to members. Comments will be accepted through Nov. 27, with staff aiming to submit a filing to FERC about Dec. 9, if the board approves the proposal.
“It felt like people had more to say, and we do want to hear what you have to say,” Asthana said.
Proposal to Modify Capacity Market Components
PJM also consulted with the MC at the meeting on a separate proposal that would revise the capacity market to include the output of some resources operating on reliability-must-run (RMR) contracts as supply, revert the reference resource to a dual-fuel CT, and remove the reactive compensation component of the energy and ancillary service (EAS) offset. (See “Insight into Upcoming Filing,” FERC Approves PJM Capacity Auction Delay.)
The 2026/27 Base Residual Auction (BRA) would be the first to use a combined cycle generator as the reference resource, a change that was made in the most recent Quadrennial Review. The higher EAS revenues for CC generators over a combustion turbine unit pushed the net cost of new entry (CONE) value to zero, affecting several parameters derived from net CONE. The variable resource rate (VRR) curve, which defines the slope of the demand curve defining auction clearing prices, would become substantially steeper, and the Capacity Performance penalty rate would fall to zero. (See “Price Cap Increases in 2026/2027 BRA Planning Parameters,” PJM MIC Briefs: Sept. 11, 2024.)
Even with the change, PJM’s Adam Keech said some locational deliverability areas (LDAs) still could see a $0 penalty rate because of the forward price estimates showing a widening spread between gas and electric prices, increasing EAS revenues for all categories of gas generation. The final net CONE will not be known until PJM completes the process of posting the revised planning parameters.
The proposal aims to address those regional impacts by replacing zonal nonperformance charge rates with a uniform penalty derived from the RTO-wide net CONE. Keech said doing so would also reflect the regional emergency capacity deployments PJM tends to experience.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if PJM has examples of dual-fuel CTs being built in the RTO’s footprint within the past five years, adding that the necessary air quality permits to run the backup fuel would be almost impossible to get in many areas, particularly in the regions capacity is needed most.
The reference resource has “to be a resource that can be realistically built,” he said.
Keech said PJM considered several restrictions that would affect the viability of virtually all technologies and looked for the lowest-cost resource that viably can be built. If it were entirely impossible to build a dual-fuel CT across the RTO, the technology would not qualify to be the reference resource, but staff believe there are enough regions where such a unit could be sited to proceed.
Vistra’s Erik Heinle, also speaking for Calpine and LS Power, said a single-fuel CT would be more appropriate as the reference resource by virtue of being viable to build in a wider range of locations.
Constellation Director of Wholesale Market Development Adrien Ford said CTs are “the pure capacity resource,” and setting it as the reference resource would reduce the impact of higher energy revenues on the capacity market.
The inclusion of expected output of generators operating on RMR agreements is aimed at Talen Energy’s 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators outside Baltimore. It would pertain only to agreements accepted by FERC by Feb. 6, 2025, and require that the units be able to operate for the entire delivery year; have sufficient run hours to address transmission violations and capacity emergencies; have deliverable CIRs; and be available for dispatch under emergency conditions unless on outage. The changes would be effective for the 2026/27 and 2027/28 delivery years while stakeholders pursue a more permanent approach to how RMR units interact with the capacity market.
Keech said it is not clear that Brandon Shores would be able to operate in accordance with those requirements because of an agreement with the Sierra Club that mandates that the plant cease coal combustion by the end of 2025, with no plans apparent to convert to alternative fuels. Wagner Unit 3 likely meets all of the criteria, but the RTO still is investigating whether Unit 4 has sufficient run hours to address the transmission needs and be available as capacity.
The RMR units would not be required to take a capacity obligation or enter into BRAs and therefore would not be subject to CP penalties nor included in the balancing ratio. Rather than paying the RMR units as if they had taken a capacity obligation, the proposal would collect capacity revenues and allocate them as credits to consumers assigned a portion of the costs associated with the RMR agreement.
LS Power Vice President of Wholesale Market Policy Dan Pierpont said PJM should ensure that it is considering how the run hours for each of the Talen units may interact. If Brandon Shores cannot operate because of the Sierra Club agreement and Wagner then needs to run more often to resolve transmission violations, that would affect its ability to meet the requirements to be modeled as supply. Keech responded that PJM would address any such interactions.
ACES Power Executive Director of Regulatory Strategy John Rohrbach said PJM is in a bind where it’s likely the Talen units will run through some avenue — either through a modification to the Sierra Club agreement or an emergency order from the U.S. Department of Energy under Federal Power Act 202(c) — but it does not have concrete knowledge of how the generators will be available. He said if PJM believes the RMR units will run one way or another, their output should be modeled.
The third prong of PJM’s proposal — to remove compensation for generators providing reactive service from the EAS offset — is in line with a FERC order finding that consumers cannot be charged for reactive service within a standard range (RM22-2). The commission’s Oct. 17 order provided PJM with more time to submit a compliance filing to determine a transition mechanism to eliminate reactive service, but it also required a separate filing to address how it is reflected in the EAS offset.
The proposed change would be a severable component of the filing, allowing FERC to approve or deny it separately from how it rules on other aspects of the proposal. (See “PJM Details Path Forward on Reactive Power,” PJM MIC Briefs: Nov. 8, 2024.)
BALTIMORE — Getting storage online in Maryland could be a critical piece of the solutions needed to address the sky-high capacity prices PJM recorded in its most recent auction, according to a panelist at a solar and storage conference.
“This is a hands-on-deck moment for Maryland to get these technologies on board,” said Joel Harrington, director of government affairs for REV Renewables, a solar, wind and storage developer. “Sitting in the PJM queue right now, just for transmission-connected storage, are 17 projects … [that] can come online in the next few years.”
Totaling 1.6 GW, those projects represent only the queued-up storage that would be located in Maryland, Harrington said, and getting them online, while not a panacea for PJM’s capacity market problems, is essential. What state regulators, the industry and other stakeholders need to figure out is “what’s going to attract, what’s going to send appropriate price signals” to developers, he said.
PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction in July, jumping to $269.92/MW-day, far above the $28.92/MW-day for the 2024/25 auction. Prices in some parts of Maryland and Virginia hit $466.35/MW-day and $444.26/MW-day, respectively. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
Harrington and other panelists at the Chesapeake Solar and Storage Association’s Solar Focus 2024 on Nov. 20 debated the options for accelerating deployment of residential and both distribution- and transmission-tied storage, as outlined in a recent report from a Maryland Public Service Commission “workgroup.”
With the passage of H.B. 910 in 2023, Maryland set ambitious targets for getting new energy storage on its electric system — 750 MW by mid-2028; 1,500 MW by mid-2031 and 3,000 MW by mid-2034 — with the goal of creating a “robust and cost-effective” storage market in the state.
The Maryland Energy Storage Initiative (MESI) Workgroup Phase 1 report is aimed at kick-starting the state market to hit the first 750-MW target. Plans for phases 2 and 3 will be developed in subsequent reports.
The workgroup recommends a multipronged approach to market development with a potential mix of utility and third-party owned storage both behind and in front of the meter, including rooftop residential and distribution- and transmission-tied projects.
In front of the meter, utilities might develop their own distribution- or transmission-tied storage or procure projects from third-party developers, the report says. The behind-the-meter market might get a boost from other state programs being developed under other laws, such as the Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256), which promotes the aggregation of renewables and storage in virtual power plants.
Another new law, H.B. 864, allows behind-the-meter energy storage to be integrated into utility demand response programs as part of a state energy conservation program.
The report stresses the integral role of aggregation in market development, not only within but also across different programs and storage sectors.
“While the financial, environmental and equity-related benefits and costs of individual storage deployments and programs should not be ignored, it is important to focus on designing an energy storage market that maximizes the aggregate value of all energy storage deployments and the entire portfolio of MESI programs for the grid, ratepayers and the state’s policy goals,” the report says. “Some benefits that storage can provide can only be realized through the aggregate behavior of many devices, and therefore these benefits can be difficult to measure at an individual project or program level.”
Non-monetizable Benefits
The MESI Phase 1 report was submitted to the PSC on Oct. 1, kicking off a comment period that ended Nov. 7. The commission is reviewing the comments and will issue an order, though no time frame has been mentioned, according to an email from a PSC spokesperson.
The panelists agreed that a core challenge for state regulators will be setting up market structures that allow storage projects to be fairly compensated for the full range of services they can provide to cut costs for consumers.
The workgroup report recommends upfront incentives in some instances, which could be critical in the residential market, said Jamie Charles, manager for grid services policy at Sunnova, a residential developer.
While cost savings are the main motivation for homeowners to install solar, “storage is really developed for resilience,” Charles said. “So, by providing these upfront incentives and providing these proposals for these grid services programs and these virtual power plant programs, that’s going to really reduce that barrier to entry.”
The report sees either the Maryland Energy Administration or individual utilities setting and distributing such incentives, which could provide a “strong foundation” for the expansion of the residential storage market in Maryland, Charles said.
Kavita Ravi, senior vice president at BlueWave Energy, a solar and storage developer of distribution-level projects, argued commercial projects should not have to pay demand charges that commercial generation projects typically pay.
“There are several benefits that storage can provide that are non-monetizable, so it’s kind of an unfair market overall,” Ravi said. “In order to allow storage to take off in the electric distribution grid, we think it is important to not levy demand charges during charging.”
Utility demand charges usually are based on specific times of highest demand; for example, when extra power is needed on cold winter days or hot summer afternoons. But for storage, demand charges often are based on the assumption that a project always will charge at its maximum capacity, which the industry has argued is not realistic.
Ravi pointed to the concept of a “wholesale distribution tariff” being developed in the Northeast specifically for storage, which “will fairly apportion the transmission costs and then the charging costs as well, which is more thoughtful and fair for storage.”
For transmission-tied storage, Harrington wants multiple options as well, including full- and partial-toll contracts and upfront incentives. A full-toll option “would be a power purchase agreement or long-term contract where you would contract for energy, ancillary services and capacity, so all three of the attributes would be a fixed price,” he said.
A partial toll would be a fixed-price contract for capacity only, with developers free to bid into either energy or ancillary services markets.
Balancing State and Local Control
Flexibility will be critical going forward, Harrington said. “Our markets [are] changing. The uncertainty around the [Inflation Reduction Act] is really making us question, how do we monetize these assets in the next four or five years? So, we need to be nimble.”
All the different procurement and contract options will “attract energy storage at some level,” Harrington said. “Every business is going to have a different option as to which one is going to attract the best investment for their business.”
The panel also talked about the need to streamline interconnection and for state standards on permitting and siting, while still allowing some flexibility for local control.
While developers will continue to look for project sites that are “non-conflict prone,” Harrington called for “the state establishing specific standards, instead of this patchwork of a developer going into each community, each town [where} they have their own set of rules and ways of regulating and permitting projects.
“The balance is being cognizant of local control, respectful of local control … but having siting standards, ordinance standards that communities can at least follow as a base,” he said.
