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November 1, 2024

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TVA Defends Rate Increase for New Gen while Nonprofit Blasts Utility’s ‘Broken Oversight’

The Tennessee Valley Authority insists its second rate increase in two years is necessary to build new generation despite the Southern Alliance for Clean Energy condemning the latest hike as clandestine and used to support fossil fuel investments. 

TVA’s Board of Directors on Aug. 22 approved a 5.25% base rate increase that will take effect Oct. 1. Last year, the board greenlit a 4.5% rise in rates. TVA said the latest increase will amount to an additional $4.35 each month for the average residential bill. 

“We don’t take this lightly; we know that customers pay bills, not rates. … We recognize that nobody likes increases,” TVA spokesperson Scott Fiedler said in an interview with RTO Insider. “But this is needed to address the tremendous growth that is happening across our region. We need to build capacity now to keep up with demand in the future.”  

Fiedler said TVA plans to spend $16 billion through 2027 to add new generation and build out infrastructure to address growth. He said the rate increase will go toward all forms of generation, including new natural gas, renewable energy and investments in the hydropower fleet. But he didn’t elaborate on how much will be spent on each category.  

Specific investments in TVA’s future fleet haven’t been revealed. TVA has yet to release its draft integrated resource plan, though Fiedler said the public can expect to see it in the fall. The draft plan was originally expected in the spring.  

Fiedler noted TVA went four consecutive years without a rate hike before 2023’s increase. He said TVA is emerging from a decade of virtually zero demand growth. 

“But now the growth we’re seeing isn’t stopping.” Fiedler said. 

Fiedler said the region’s population is growing three times faster than the national average and by 2050, the University of Tennessee’s Baker School of Public Policy and Public Affairs projects the region’s population will have grown by 22%. He said the region will gain in the long run from the economic boom in the form of additional tax revenues.  

“The benefits are there, but we understand it can be a hardship,” he said.  

“We have done everything possible to absorb costs as we invest in the reliability of our existing plants, construct new generation to keep up with growth and maximize solar to produce more carbon-free energy,” TVA CEO Jeff Lyash said in a press release after the board approved the increase. 

Fiedler said TVA is attempting to blunt the load growth by devoting $1.5 billion to its new energy efficiency program, TVA EnergyRight, which offers rebates for things like HVAC checks, new air conditioning units and attic insulation. 

He said TVA’s efficiency goal is to offset about 30% of the new load coming online over the next decade. He also said TVA has pledged to reduce its internal costs by $900 million over the next three years.  

Fiedler also noted that TVA has applied for a grant through the Department of Energy’s Grid Resilience and Innovation Partnerships to support a new transmission project to transport renewable energy from the Midwest into the Valley.  

By all appearances, TVA’s IRP will hinge on new natural gas generation. TVA has announced it will replace two coal units at its 2,470-MW Cumberland Fossil Plant with a 1,450-MW natural gas plant. Early this year, FERC approved a pipeline meant to feed the plant, although TVA has said its decision to build the gas plant isn’t final. (See FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant and TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.)  

Several clean energy organizations and two Tennessee congressmen have criticized TVA’s IRP process as secretive, with little public analysis and inadequate opportunities for public influence. (See Tenn. Congressmen Introduce Bill to Make TVA IRP Process More Public.) 

The Southern Alliance for Clean Energy (SACE) said TVA’s rate increase was likewise shadowy and emblematic of a “broken oversight process.” It said board members allowed the hike “without any public documentation showing why the increase is needed or how those additional revenues will be spent.”  

“Only in the Tennessee Valley could a major utility raise rates without public scrutiny of financial documents,” SACE said in a press release, speculating that an “expensive gas expansion is a likely culprit” behind the increase.  

The nonprofit said TVA’s rate increases this year and last are “strategically set just below a 10% threshold that would trigger renegotiation of hundreds of power supply agreements with local utilities.” It bemoaned the fact that the federal utility’s rate increase was not subject to independent regulatory rate reviews by an agency like a state public service commission.  

“People across the Tennessee Valley will see electric bills increase because their public power utility has spent their hard-earned money on plans that it refuses to release to the public. But what is perhaps most disappointing is the fact that the people of the Tennessee Valley have never known anything different. They do not know that most utilities must present a detailed case for public scrutiny before raising rates. TVA has a visage of public power as a federally owned utility but operates as an unregulated private monopoly,” SACE Research Director Maggie Shober said in a statement last week. 

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New IIJA Funding Seeks to Close Gaps in EV Charging Networks

Los Angeles County will use its $15 million Charging and Fueling Infrastructure (CFI) grant to install 1,263 Level 2 electric vehicle chargers at 15 community facilities, four park-and-ride transportation hubs, and 1,000 curbside light poles, according to the Federal Highway Administration’s Aug. 27 announcement of CFI grants totaling $521 million. 

The Los Angeles chargers are one of the 51 projects receiving federal funds from the Infrastructure Investment and Jobs Act (IIJA), with the goal of installing chargers and alternative fueling stations “in the places people live and work ― urban and rural areas alike,” the FHWA said.   

The projects are spread across 29 states, the District of Columbia and eight tribal communities and split between 41 community-focused projects, receiving $321 million, and 10 “corridor” projects, receiving $200 million to install DC fast chargers along major highways and other roads designated as “alternative fuel corridors.”  

California received the largest award, $102 million, to install DC fast chargers and hydrogen fueling stations for medium- and heavy-duty trucks along 2,500 miles of key freight corridors running through California, Oregon and Washington state. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.) 

The FHWA description notes that “the project will enable the emissions-free movement of goods connecting major ports, freight centers and agricultural regions between the U.S. borders with Mexico and Canada.”  

University City, Mo., a St. Louis suburb, got one of the smallest awards ― $500,000 ― to install its first EV chargers along the main street in a historically disadvantaged neighborhood.  

“As we build out the EV charging network on our highways, we are also investing in local communities, rural, urban and tribal alike,” Polly Trottenberg, deputy secretary of transportation, said in an FHWA announcement. “Today’s grants are a critical part of ensuring every American can find a charger as easily as a gas station, which will decrease pollution from our roadways, lower costs for families and help people get to where they need to go efficiently.”  

Borrowing a favorite line from President Joe Biden, Energy Secretary Jennifer Granholm said the CFI grants are “building infrastructure from the bottom up and the middle out. This investment puts public dollars in the hands of states, tribes and communities to build a more accessible national charging network.” 

The IIJA provided $2.5 billion for the competitive CFI program and an additional $5 billion for the National Electric Vehicle Infrastructure (NEVI) program, which allocates funds to each state based on a formula that accounts for factors like population, vehicle miles traveled and the number of registered EVs in the state. 

NEVI funds are aimed primarily at building out a network of DC fast chargers along U.S. highways, with the FHWA setting standards that require the federally funded charging stations to be located about every 50 miles along major routes and provide at least four 150-kW fast charging ports with 97% reliability. 

The competitive CFI grants are supposed to fill in gaps at the community level, where low-income and disadvantaged areas, and neighborhoods with multi-unit housing, may have few if any publicly available chargers.  

Other CFI grants include: 

    • $11.8 million to Atlanta, Ga., to build a hub of 50 DC fast chargers at the city’s Hartsfield-Jackson Atlanta International Airport. The hub will “provide critical charging for rental car companies, ride-share drivers, airport shuttles for hotels, employees … as well as regional and local EV drivers coming to the airport.”  
    • $2.8 million to Ann Arbor, Mich., to install 48 publicly available EV chargers to “close gaps” in the city’s charging networks. Key locations for the new chargers will include park-and-ride lots, multi-unit housing and large retail areas. 
    • $15 million to the Fort Independence Indian Community, also in California, to build a charging hub along U.S. Route 395, the only north-south corridor along the Eastern Sierra Nevada range. The hub will be powered by a solar microgrid with combined heat and power generation and battery backup.   

The first round of CFI funding, for $1.14 billion, was announced in March 2023; it drew 277 applications, seeking $2.1 billion in grants. A first round of awards, for $623 million, was announced in January. The current announcement covers grants for some of the applications that previously did not receive awards. 

A notice of funding opportunity for the second round of CFI grants totaling $1.3 billion was announced in May; the deadline for applications is Sept. 11.  

NEVI Rollout Blues

With the passage of the IIJA, and its NEVI and CFI programs, Biden set an ambitious goal to have 500,000 convenient, reliable and user-friendly chargers installed and online by 2030. 

According to the FHWA, the number of publicly available chargers has doubled since Biden took office. The national total now stands at 192,000, with an estimated 1,000 new chargers coming online each week. The newly announced CFI projects could add an additional 9,200 chargers to the total.  

But public perceptions of the U.S. charging network continue to be a significant roadblock to EV adoption. A January 2024 survey by McKinsey & Co. found that 80% of survey participants considering an EV purchase thought the existing charging system is inadequate. A majority said they would not buy an EV until public charging is as available as gas stations are at present.  

McKinsey estimated that as EV demand grows, the U.S. could need 9.5 million charging ports by 2025 and 28 million by 2030. 

In the face of such numbers, the NEVI program appears to have had little impact thus far. The Joint Office of Energy and Transportation, which has been tracking the NEVI rollout, reported that as of the end of May, eight NEVI-funded charging stations, with a total of 33 ports, had opened in six states: Hawaii, Maine, New York, Ohio, Pennsylvania and Vermont.  

Since that time, Rhode Island and Utah have also opened their first NEVI stations, and a growing number of states ― including Georgia, New Hampshire, Virginia, Indiana, Arkansas, Kansas and Wisconsin ― have awarded contracts for their first NEVI stations. 

Charger reliability also remains a major concern among prospective EV buyers. According to figures from the Joint Office, in July, about 7.4% of all publicly available Level 2 chargers were temporarily unavailable, compared with just 2% for DC fast chargers. 

The FWHA is addressing the reliability issue with another IIJA-funded initiative ― the Electric Vehicle Charger Reliability and Accessibility (EVC-RAA) program ― which is providing close to $150 million in grants for the repair, upgrading or replacement of older EV chargers. On Aug. 22, the Joint Office of Energy and Transportation joined with Washington, D.C., officials for a “ground re-breaking” at an inoperable charger in the city. Originally a 50-kW charger, the upgraded station will have four ports, all capable of charging at 150 kW. 

The EVC-RAA program is targeting repair and upgrading of 4,500 charging stations, according to the Joint Office. 

While seeking to respond to consumer concerns, Gabe Klein, executive director of the Joint Office, argued that the EV charging experience is significantly different from fueling up at a gas station, with consumers benefiting from the reduced costs of operation, reduced carbon emissions and improved public health.  

“Most EV charging will happen at homes, workplaces or other destinations while vehicles are already parked, providing a safe, reliable and vastly more convenient way for anyone to fuel,” Klein said. “[The CFI] investments in public community charging fill crucial gaps and provide the foundation for a zero-emission future where everyone can choose to ride or drive electric for greater individual convenience and reduced fueling costs, as well as cleaner air and lower healthcare costs for all Americans.” 

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Parties Argue for More Changes to Interconnection Rules from FERC

Even as it works to implement Order 2023, FERC is considering additional changes to its rules on generator interconnections, with a technical conference set for Sept. 10-11 that saw pre-conference comments filed this week (AD24-9).

Commenters argued for a more proactive transmission planning process that takes into account the future generation mix. Others argued for greater automation and certainty around planning.

Some pushed for a special “fast track” for shovel-ready generation that is needed as the grid continually sees generators retire that need to be replaced. The bulk of the new generation in queues is made up of renewable energy; National Grid said that has helped to overwhelm processes originally designed for a more limited volume of fossil fuel-fired plants.

“Unfortunately, the measures that have been relied on historically — e.g., increased deposits and fees, penalties, and prioritizing first-ready projects — have proven insufficient to address the challenges of a rapidly changing grid driven by unprecedented levels of investment in the energy transition,” National Grid said.

Fixing the situation will require new methods, such as a competitive, priority queue for projects that can readily address reliability needs and better coordination between long-term transmission planning and the generator interconnection process, the company said.

“While a capped queue provides an effective means of getting the GI queues under control and more aligned with realistic and effective grid administration, we cannot lose the value that competition in the generation sector has provided for system reliability and consumer costs,” National Grid said. “Accordingly, to populate the capped priority queue, our proposal would establish a competitive process based on identified needs to select the projects that would form the relevant queue.”

Constellation Energy also supported an expedited queue, noting that ISOs and RTOs have increasingly warned that the trends of accelerating retirements and clogged queues could lead to reliability issues if not addressed in the coming years. Its comments argued for an “Expedited Reliability Process” for reliable, deployment-ready projects, such as uprates to its nuclear plants.

“Constellation has announced approximately 135 MW of planned uprates at our Braidwood and Byron generating stations in Illinois, the equivalent of adding 216 variable-output wind turbines to the grid,” the company said. “In total, nuclear operators across the nation are considering or preparing uprates with a cumulative capacity increase of approximately 2 GW.”

Such uprates and other shovel-ready projects can plug the reliability gap, but they have to sit in queues that have been gummed up with projects that often contribute far less to resource adequacy, Constellation said. Under its proposal, RTOs would be able to set up an expedited queue when they determine some projects would more effectively and quickly address identified reliability needs.

“RTOs concerned that reliability and/or resource adequacy is becoming an issue could, in these narrow circumstances, seek commission approval of an expedited interconnection study process that would prioritize the processing of interconnection requests likely to be responsive to the RTO’s reliability and/or resource adequacy need, and that can demonstrate a high degree of readiness,” Constellation said. “This subset of interconnection requests would be moved through the interconnection study process on an expedited basis so they can be put in place quickly in response to the RTO’s demonstrated reliability and/or resource adequacy need.”

Storage developer Gridstor cautioned FERC against doing damage to the concept of open access in attempting to speed up queues.

“The commission should look to solutions that least compromise open access and make prioritization criteria based as much as possible on the actions and decisions under the control of interconnection customers,” Gridstor said.

Rationing interconnection quests to determine advancement introduces a zero-sum process because only some projects would get into the priority queues. It could even lead to discrimination among similar projects, the company said.

In the past, FERC has limited exceptions to open access to new generators using retired units’ interconnection facilities and to surplus capacity available to existing generators that want to expand. Gridstor argued the main issue leading to the long queues is a lack of adequate transmission, so any expedited, special processing should be time limited.

“It is imperative that the commission should seek a limiting principle — that is, the smallest compromise to open-access principles needed to achieve the goal of rationing interconnection requests,” Gridstor said. “Reforms that go beyond what is strictly necessary to address the current supply-demand imbalance should be rejected, given the more fundamental responsibility of the commission to uphold open access principles.”

Marrying Interconnection and Transmission Planning

The technical conference will also consider arguments around proactively expanding the grid, which would spread the costs of connecting new resources more broadly than they are now.

“Closer integration of generator interconnection and transmission planning processes will result in a more efficient buildout of the electricity grid,” Brattle Group Principal John Michael Hagerty said. “The vast majority of transmission upgrades today are identified through siloed processes, based on grid reliability studies (with limited consideration of future resource needs) and generation interconnection studies. Proactive transmission planning processes that holistically account for both future projected demand and changes in the future generation resource mix and consider a comprehensive set of transmission benefits will identify the upgrades that reduce total customer costs and allow new resources to efficiently enter the system through the generator interconnection process.”

Hagerty’s comments drew from a report he co-authored with Grid Strategies for Advanced Energy United and the Solar and Storage Industries Institute on potential changes. It argued that proactive planning will avoid unneeded upgrades identified through siloed reliability studies and result in more cost-effective upgrades that provide access to more new resources.

Such plans need to be based on multiple scenarios to deal with the uncertainty around the future. Hagerty said a reasonable cost-allocation method would also help.

“Proactive planning does not require a specific approach to cost allocation for the new transmission upgrades,” Hagerty said. “Identifying a reasonable cost allocation approach that aligns costs with beneficiaries will be an important step in implementing an integrated planning and interconnection process.”

Regions could continue to assign upgrade costs to generators, but they would fund a smaller percentage of a larger suite of transmission upgrades developed for their use, he added.

The R Street Institute also argued for proactive planning and broader cost allocation, as it had earlier in FERC’s transmission planning rulemaking. Those would lead to lower costs overall, meaning lower bills for consumers.

“This improved efficiency translates into major cost reductions for network upgrades, which consumers ultimately pay for, either directly or indirectly,” R Street said. “Because transmission costs are so heavily incurred by consumers, large savings from more efficient network upgrades reduces costs to consumers irrespective of cost allocation method.”

R Street cited ERCOT’s “connect and manage” system, in which transmission network upgrades are entirely determined in planning, and generator interconnection does not include deliverability requirements, leading to much lower barriers to entry than the “invest and connect” approach used in other markets.

“Transmission costs are borne by consumers, either directly or indirectly,” R Street said. “Therefore, it is in consumers’ best interests that transmission expansion efforts be most efficient. Separating network upgrades from the generation interconnection process is one way to improve efficiency.”

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FERC Report Identifies CIP Audit Lessons Learned

FERC identified several areas where registered entities can improve their compliance with NERC’s Critical Infrastructure Protection (CIP) standards in audits conducted over the past year, the commission said in a report released this week.  

The Lessons Learned from Commission-Led Reliability Audits report is the latest in a series released each year since 2016. Each report covers the preceding fiscal year, which runs from Oct. 1 to Sept. 30. During the fiscal year, FERC staff conduct audits with select utilities, which comprise “data requests and reviews, webinars and teleconferences, [and] virtual and on-site visits,” FERC said in the document. Staff from NERC and the regional entities participated in the audits along with FERC’s Office of Electric Reliability and Office of Enforcement.  

Both in-person and virtual visits required interviewing entities’ subject matter experts and observing staff operating practices, processes and procedures. Auditors spoke with employees and managers who handled tasks within the audit scope and reviewed documentation to verify CIP compliance. As in previous years, details about the audits — such as how many audits were performed and which utilities were visited — were not disclosed. 

In addition, FERC and ERO staff conducted field inspections remotely to observe the functioning of cyber assets — referring to programmable electronic devices including hardware, software and data — that the entity classified as high-, medium- or low-impact as required by the CIP standards. The criteria for identifying a cyber system’s impact level are found in CIP-002-5.1a (Bulk electric system cyber system categorization). 

The report’s authors found that, overall, “most of the cybersecurity protection processes and procedures adopted by the registered entities met the mandatory requirements of the CIP standards.” However, FERC also noted common missteps that could result in “potential noncompliance and security risks.”  

FERC discussed five lessons learned in the report, one more than in last year’s assessment but the same as in the 2022 report. (See FERC’s CIP Report Finds Fewer Issues Again.) The issues identified relate to four standards: 

    • CIP-002-5.1a 
    • CIP-010-4 — Cybersecurity: configuration change management and vulnerability assessments 
    • CIP-011-2 — Cybersecurity: information protection 
    • CIP-012-1 — Cybersecurity: communications between control centers 

Two lessons in the report arose from CIP-002-5.1a, specifically requirement R1. The requirement directs entities to identify cyber systems and assets, and determine the impact that their loss, compromise or misuse could have on grid reliability. 

FERC said auditors found some cases in which entities installed cyber assets — specifically, firewalls — whose risks were not properly categorized. The report said there was a chance that if these devices failed to operate correctly, they would fail “closed,” meaning network traffic could not flow to maintain normal network behavior.  

While the devices were outside the entities’ electronic security perimeter (ESP) and thus did not technically meet the definition of cyber asset, the report said they may affect cyber assets to the point of impacting reliability. FERC recommended entities consider enhancing their categorization procedures to catch such assets and ensure their potential impacts are noted. 

The standard also requires entities to evaluate segmented control centers at a single location as a single control center in their asset identification and categorization procedures. FERC said some entities improperly segmented a single control center into multiple centers that “were logically segmented by electronic access controls.” 

The report said entities had done this in order to “reduce the compliance risk associated with the … CIP reliability controls [but] were not fully aware of the limitations of segmentation within the CIP standards.” If cyber systems are not properly classified, FERC said, entities “may not apply the require controls consistent with the risk.”  

‘Multiple Instances’ of Cyber Risk

For the remaining standards, the commission identified a single lesson learned for each. CIP-010-4 requires that entities include “all intentionally installed, commercially available software on each cyber asset” in their cyber asset baselines, including both standalone applications and related browser extensions. However, FERC noted cases in which entities did not specify whether the standalone application or the extension was installed on a system.  

FERC said this practice could create problems when an entity experiences issues and needs to restore a system from backup. It warned that if baseline documentation is incomplete or incorrect, proper restoration could become “challenging, if not impossible.” Inaccurate documentation could also affect the accuracy of the entity’s security posture. 

Next, the commission turned to CIP-011-2, and its requirement that entities “implement controls to protect [grid] cyber system information … to mitigate the risks posed by unauthorized disclosure and unauthorized access.” Audit staff did not go into details of noncompliance with the standard, saying only that “in some cases, not all entities consistently implemented adequate controls to identify, protect and securely handle” cyber system information. The report said staff found “multiple instances” of cyber information-related risk in their audits. 

The final lesson learned was from CIP-012-1, which mandates that entities identify and address the possibility of unauthorized disclosure or modification of real-time data transmitted between control centers within a single network, ESP or other environment.  

FERC said that while entities “generally had strong processes and procedures for” identifying relevant communications, “some failed to recognize or categorize the communications paths internal to their own networks.” In particular, the commission said some entities did not realize the connection between their primary and backup control centers is covered by the CIP-012-1 requirements. The report’s authors said entities should expand their identification of real-time communications to include all control centers, including those within their own environments. 

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AEU Presses Call for Streamlined State Permitting

Aligning thousands of local governments toward development of renewables remains one of the harder nuts to crack in the clean energy transition. 

Advanced Energy United this summer offered core policy considerations to speed up the process and held a webinar Aug. 27 to drill down on how state-level efforts to streamline permitting have been progressing. 

“Local opposition recently was cited in a survey of developers as one key barrier to getting projects done,” said Trish Demeter, an AEU managing director and the moderator of the discussion. “By another estimate, more than 15% of counties in the U.S. have some sort of ban or restrictive ordinance on new renewable energy projects.” 

Discussion centered on Massachusetts and Michigan, which have both declared 100% net-zero and clean energy goals. Both also delegate extensive power over clean energy projects to hundreds of local governments that are not uniformly enthusiastic about hosting sprawling new generation facilities. 

The goal is to streamline the control these local governments can exert over the approval process around a single set of principles rather than an ever-changing assortment of hundreds of rules. 

Jim Purekal, an AEU policy director, summarized the principles the trade group laid out in July as critical to large-scale development: 

    • uniform siting criteria and permitting conditions, or reasonable ranges of variation. 
    • predictable and consistent permitting environments with clearly defined steps. 
    • the absence of explicit, or de facto, moratoria or bans. 

“Now, we at United are not equipped or oriented to engage with every local agency that’s out there, or to engage on every project-by-project basis,” Purekal said. “So, these principles are really focused on the state policy advocacy, and that’s where we have a more established presence with respect to access to decision makers and also legislators and governor’s offices in about 20 states.” 

Representatives of developers working in Massachusetts and Michigan described local governance in both states that was detrimental to their work. 

Jessica Robertson of New Leaf Energy said county and regional governments do not have siting authority in Massachusetts, so 351 cities and towns rely on their individual zoning codes and standards to review projects smaller than 100 MW. 

Nearly everything so far in the Bay State has been smaller than 100 MW, except for energy storage, and grid-scale storage has its own set of hurdles. 

“Municipalities at the moment have a pretty wide ability to say ‘no’ and not give projects a permit at all,” Robertson said. “And there are different types of ways you can appeal or challenge, depending on exactly what the situation is, but those all add years to the process. 

“The same thing happens with abutter appeals. There’s a very broad authority for abutters to appeal projects in Massachusetts.” 

Chris Kunkle of Apex Clean Energy painted an equally negative picture in Michigan’s 1,240 townships. 

As Apex developed the 383-MW Isabella Wind 1 and 2, the largest clean energy project in the state, it had to contend with seven townships, seven sets of regulations that could be changed mid-process and seven sets of leaders who in some cases faced recall petitions for not opposing the project. 

“It created an environment that is simply just not conducive to the scale and pace of renewable energy development that the state of Michigan needs, from our perspective,” Kunkle said. 

Both states are governed by a Democratic executive-legislative trifecta, and both introduced streamlining measures to limit local obstruction to renewables. Both measures preserve some aspects of local control, but both created the backstop option of state review for larger projects. 

Michigan’s package was signed into law Nov. 28. (See 100% Clean Energy, Renewable Siting Bills Heading to Michigan Governor.) 

Massachusetts’ permitting reform proposal was left hanging when the legislature adjourned Aug. 1. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform.) 

Robertson is optimistic the measure will yet become law — there is general agreement on the principles, she said, it just could not get through the last-minute rush in which a lot of legislative decisions are made. 

Given the breadth and intensity of NIMBY sentiment that surrounds vast solar arrays on former farm fields and wind turbines towering over the countryside, or shipping containers full of batteries that have been known to spew toxic smoke, building a consensus on permitting reform can be a tall order. 

It’s essentially a group of lawmakers in a distant capitol asking a community to host a tiny part of the solution to problems that affect the state, nation and planet, and stripping them of their ability to say “no.”  

It does not play well with lawmakers’ constituents there. 

“That’s a tension that had not been resolved previous to this,” Robertson said. 

“There was some conflict along the way, there’s no other way to put it. There’s differing viewpoints,” Kunkle said. “The local government organizations didn’t support this bill. They wanted to preserve their ability to deny projects around the state.” 

So how does such a proposal gain enough support to become law? 

Gaining Democratic control of the governor’s office and both houses of the legislature was key in Michigan, Kunkle said. But beyond that, he said, there was a lot of education of stakeholders about the local benefits of clean energy such as construction jobs. There also needs to be a skilled and energetic sponsor of legislation who can build support for the proposal. 

Robertson said the community members most likely to get involved in the permitting process are those opposed to a project. So, it’s important to figure out early what would make the project a “win” for that community, then get that message out, particularly amid disinformation campaigns. 

The message needs to be tailored to the audience, she added. A pitch in Massachusetts might emphasize climate protection, for example, but neighboring New Hampshire might be more receptive to the idea of energy independence and keeping energy dollars local. 

Kunkle said all the clean energy goals set by states such as Michigan and Massachusetts need to be backed up by a regulatory structure that gives them a chance of being achieved. 

“If you still leave permitting decisions in the hands of local government, we’re going to continue to stumble as an industry and fall short of those goals,” he said. 

Purekal ran through some of the policy considerations AEU emphasizes as it presses for siting reform: 

    • Cut red tape to streamline and right-size the process. 
    • Establish clear and enforceable timelines for permit application processes. 
    • Clarify and consolidate the appeals process. 
    • Explore incentives and tax options that would soften local opposition. 
    • Consider community benefit agreements. 
    • Promote industry best practices around decommissioning. 

But there is a place for flexibility amid all this standardization, Purekal said. “That’s flexibility to tailor agreements with host communities based on the needs of the community in order to create buy-in and meet localities where they’re at by looking at their specific needs.” 

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National Grid Lining up 70-plus Transmission Projects

Hundreds of projects are in the works across New York to make its grid better able to handle storms and the clean energy transition that state leaders are trying to implement.

Major new lines draw attention with their multibillion-dollar, multi-gigawatt proportions, but they are far outnumbered by their much-smaller cousins. All of the state’s electric utilities are doing this work to some degree; the leader of National Grid’s campaign spoke to RTO Insider about that utility’s plans.

National Grid’s Upstate Upgrade is a portfolio of more than 70 projects announced in March that will continue through 2030. Early components include 115-kV line updates, new and rebuilt substations and supporting work such as access road improvements.

None of these upgrades has the profile of the 340-mile, $6 billion HVDC line being built to import electricity from Canadian hydropower plants, but altogether, the Upstate Upgrade is expected to cost more than $4 billion. And National Grid plans billions of dollars in additional work beyond that.

New York’s efforts to decarbonize are experiencing delays and cost escalations. But if anything close to the projected increases in electric generation and demand materialize, much more than the Upstate Upgrade is likely to be needed.

The state Public Service Commission has authorized upgrades costing billions and has set the stage for billions more in spending through planning processes that anticipate future needs rather than respond to present needs.

Bart Franey, National Grid’s New York vice president of clean energy development, said the Upstate Upgrade consists of two phases, both informed by this need to anticipate future demand.

Phase 1 is refurbishment of older infrastructure that National Grid was going to do anyway for purposes of reliability and resilience but decided to proactively expand in expectation of needs created by the state’s decarbonization policies and goals.

Phase 2 is purely proactive upgrades that might not have been contemplated were it not for the growing demand for clean electricity.

Pockets of renewable power generation are growing in rural areas of New York that are removed from population and industry centers, Franey added, something not anticipated when the grid was built decades ago.

“Not unlike other utilities, our grid is pretty old,” he said. “Its original design was to serve those remote rural communities and industries. Now it’s being asked to export way more power on the same circuit. That bidirectional nature always existed, but rather than serving a couple hundred megawatts, we’re now demanding that it export 1,000 or more megawatts.”

Of interest to the host communities, the upgrades will harden the grid against severe weather. They also will create temporary economic benefits during construction and longer-term development opportunities when the work is completed.

Slow and Costly

A series of reports this summer shows the scope of the task facing New York as it tries to decarbonize and shows the impediments to progress that have been cropping up.

NYISO on July 23 issued its latest System and Resource Outlook. Highlighted in boldface was the assessment that “historic levels of investment in the transmission system are happening but more will be needed.”

The outlook notes that New York’s electricity consumption is expected to increase 50 to 90% over the next 20 years as heating and transportation are electrified; large industrial loads are added in the upstate region; and the installed generation capacity as much as triples.

Also in July, the two state entities in the forefront of the energy transition reported that New York is likely to miss its goal of 70% renewable energy by 2030, perhaps by a wide margin, due to delays and cost overruns.

The state comptroller reached the same conclusion in an audit that also faulted the same two entities for not telling New Yorkers how much the grand vision may cost.

Price tags for individual projects and initiatives are being announced as they are approved, but no estimate has been offered of the total cost of decarbonization in a state that has some of the highest taxes and utility rates in the nation.

It’s also worth noting that upstate utilities have had a fairly static customer base. Census data shows that from 1970 to 2020, the population of the 11 southernmost counties (in and around New York City) grew 14.5%, but the 51 upstate counties grew only 4%,

And most of that growth was concentrated in a handful of places — take away the top four counties and the upstate population actually shrank 0.6% during a half century when the nation’s population grew 63%.

Franey offers a financial equation sometimes used to justify the costs of transmission projects: Putting more load on the grid spreads the cost of operating the grid more widely, lowering the cost for the small ratepayers who do not increase their electric use.

And he rejects the criticism sometimes leveled at transmission projects, that utilities love them for their regulated rate of return. Nothing is guaranteed, Franey said, especially in an era of more frequent and more severe storms.

But the Upstate Upgrade is about more than moving electrons north to south, he said.

“I get it, it’s cost, cost, cost. But I don’t think anyone talks about the value as much as they ought to,” Franey said. “The value that we’re talking about with jobs, the value we’re talking about with increased tax [revenues]. These communities have not seen this type of economic activity — where that generation is being sited and built, where that cheap power is coming in, where those crews are spending their money — in a hundred years.

“What is frustrating for me as a practitioner in this space is, no one is talking about value.”

Beyond the value of the project itself is the value of more electricity becoming available: It facilitates economic development.

The biggest example is Micron’s plan to build a semiconductor manufacturing complex near Syracuse at a cost of up to $125 billion.

National Grid is seeking approval to construct eight new 345-kV underground laterals from an expanded substation to service the site — one to each planned chip fab plant plus one redundant line to each to ensure reliability.

With NYISO projecting a need for installed generation capacity to expand from 40 GW today to 100-130 GW by the early 2040s, a steady demand for new transmission seems inevitable.

“No matter what we do,” Franey said, “we could never overbuild, because there’s just so much demand between a data-driven economy, between large spot loads, between electrification of transport, between electrification of heating, and the new power flow dynamic that’s being set up by renewables being sited remotely from the grid. If we put capacity out there, it is going to get used.”

The landmark Niagara Mohawk building in Syracuse is shown. National Grid acquired the New York electric and gas utility in 2002. | Shutterstock

As a lifelong upstate resident, Franey sees these developments as positive not only for the utility but for a region whose economy has stagnated or declined for generations.

So the clean energy transition is a potentially major change in more ways than one.

“You used to get requests [for] 2, 3 MW, and now it’s like 2 to 3 MW is nothing. Now, it’s just like, hey, can you give us 30?” Franey said. “And again, I don’t think it’s a bad thing. I think that’s actually a good thing. I like to see economic growth. I like to see people using more electricity.”

A Century Old

National Grid is the largest of the five investor-owned electric utilities operating in upstate New York, where its 5,600 employees serve 1.7 million customers under the legacy name Niagara Mohawk, the electric and gas utility National Grid acquired in 2002.

It operates 5,600 miles of transmission lines with 275 transmission substations and 47,000 miles of distribution lines with more than 500 distribution substations across a 25,000-square-mile service area, which is about half the state’s total footprint.

Dial back a century, and the picture is not so impressive.

Thomas Edison switched on the state’s first electric grid in 1882 in lower Manhattan, but 40 years later, dark areas still dotted New York. Dozens of utilities — 59 of which would merge in 1929 to form what is now National Grid — were still extending power lines to rural areas.

One of those was the Taylorville Line, which in 1925 electrified a glacier-carved area of forests, farms and small villages south of the Canadian border.

Some of that original infrastructure remains in service in 2024. Pieces have been replaced for safety or reliability reasons, but the rest is still doing what it has done for 99 years: moving electrons through a sparsely inhabited area from one population center or generation center to another.

The difference now is that these sparsely populated areas are prime real estate for the wind turbines and solar panels New York wants to bring online in large numbers.

The Taylorville Line’s original structures would be replaced as a Phase 2 project to accommodate anticipated renewable generation construction.

“We always say age doesn’t necessarily indicate that the assets need to be replaced,” Franey said. “Having said that, they were built to a different spec, different construction standard, and so now, going in with newer construction standards, you’re modernizing it. They’re going to be hardier; they’re going to be able to weather storms, severe events, much more. Back then it was all about, ‘Let’s electrify the rural areas.’”

The Upstate Upgrade is foundational in many ways, particularly Phase 2 — it is not the final step, but it is necessary groundwork for large-scale decarbonization.

For example, National Grid is beginning to think about virtual power plants but it would be a while before it could create them. For that, it would need more transmission capacity to power more chargers to encourage more people to buy electric vehicles to set the stage for a vehicle-to-grid scheme that would be large enough to be meaningful.

EV adoption so far has been tepid in large swaths of National Grid’s upstate territory.

The best example is Lewis County, which includes the area known as Taylorville.

One state database shows just 79 plug-in hybrid and battery electric vehicles among the 16,560 passenger vehicles registered in the county of 26,582 residents; another shows a total of four public charging stations in its 1,274 square miles.

That is the fewest EVs of any of the state’s 62 counties except nearby Hamilton County, a wilderness area with only 5,100 year-round residents. And even Hamilton County has significantly more EVs registered per capita than Lewis County.

But there are other non-wire solutions that make sense in the near term as National Grid begins the Upstate Upgrade.

Grid-enhancing technologies, for example, can delay the need for new wires while a better picture develops of what the future needs will be and while new technology potentially is developed to meet those needs.

“We are doing a couple of grid-enhancing technologies, dynamic line ratings,” Franey said. “The value proposition there was, it’s not a permanent solution, but it’s a relatively inexpensive solution that gets us to a point where we would absolutely need to make that transition over to a more permanent solution.”

He added: “This is all burgeoning technology. We’re getting comfortable with it. We’re integrating it into the control room operations. We haven’t even gone through a full calendar year hitting all seasons yet, so we’re still learning and adopting it, but we have more in the queue, more in the pipeline. It shows a lot of promise.”

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BPA Postpones Day-ahead Market Decision Until 2025

The Bonneville Power Administration will delay its decision on choosing between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM) until May 2025, the federal power agency said Aug. 26. 

In a message circulated on its “tech forum” email distribution list, BPA said it will extend its day-ahead market decision-making process into next year, with a draft decision to be issued in March 2025, followed by a final decision in May. Sources told RTO Insider last week that the announcement of such a delay was imminent after BPA CEO John Hairston said he was evaluating the decision timeline. (See related story, BPA to Delay Day-ahead Market Decision, Sources Say.) 

“This revised schedule will provide additional time to continue comprehensive analysis of market options,” BPA said in the message. “Bonneville recognizes the importance of its day-ahead market decision to the region, our customers and stakeholders. Bonneville remains committed to advocating for a market design that is consistent with our statutory obligations.” 

Both markets have “outstanding issues that require additional analysis,” BPA noted. 

For Markets+, that includes the deficiency notice FERC issued SPP last month in response to submission of the market’s proposed tariff. 

“While SPP is preparing responses, the Markets+ tariff remains unapproved. SPP Markets+ stakeholders continue to engage in protocol development as the tariff process progresses,” BPA said. 

SPP officials this month played down the significance of the notice, saying the commission’s questions were part of a “routine process” and didn’t pose a “serious risk” to the future of the market. (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

BPA also said it “will continue to fund and commit staff resources to the Markets+ design effort in collaboration with SPP and Markets+ participants,” although it’s not clear yet whether that includes a commitment to funding its share of the estimated $150 million price tag for the Phase 2 implementation stage of the market, which is scheduled to begin next year. 

Regarding CAISO’s EDAM, BPA acknowledged the progress the West-Wide Governance Pathways Initiative has made in getting ISO board approval for giving the Western Energy Markets Governing Body “primary” authority over the market. But it also pointed out that the effort to pass California legislation needed to give that body “sole” governance authority over the EDAM and Western Energy Imbalance Market is still “in the early stages.” 

“Bonneville has been consistent that legislative changes are needed to give EDAM an independent governance structure. Independent market governance that is not obligated to any single state, entity or trade association is paramount for Bonneville to participate in a day-ahead market,” the agency said. 

BPA said it plans to hold additional public day-ahead market workshops on Nov. 8, 2024, and Feb. 6, 2025. It will also schedule a March 2025 workshop after release of its draft market decision. 

“Bonneville appreciates the feedback received in favor of extending the decision timeline. By allowing more time for analysis and further development of EDAM, Pathways and Markets+, Bonneville can make a more informed decision regarding potential market participation for the good of our customers and the Pacific Northwest region,” the agency said. 

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West Coast Truck Charging Corridor Wins $102M in Federal Funds

California ZEV infrastructure projects are receiving $150 million in federal funding, including $102 million for a tri-state charging network for medium- and heavy-duty trucks.

The money is from the Federal Highway Administration’s Charging and Fueling Infrastructure competitive grant program, which was created by the Bipartisan Infrastructure Law. U.S. Sen. Alex Padilla (D) announced the grant awards Aug. 26.

The bulk of the funding — $102.4 million — is going to the West Coast Truck Charging and Fueling Corridor project, a joint effort of the California, Oregon and Washington departments of transportation and the California Energy Commission (CEC). The corridor would stretch from border-to-border along the West Coast.

As described during a workshop last year, it would include 34 truck stations and five hydrogen fueling stations. The stations would be primarily along Interstate 5, with some locations on “key connecting corridors,” such as I-710 in the Los Angeles area. (See EV Charging Efforts Ramp up on West Coast.)

“To successfully meet California’s critical climate goals, we need to scale up our charging and fueling infrastructure up and down the state through transformative projects like the West Coast Truck Charging and Fueling Corridor project,” Padilla said in a statement.

The three state DOTs and the CEC applied for the Charging and Fueling Infrastructure grant funding in June 2023. California Democrats who supported the tri-state corridor described it as a $700 million project.

“This first-of-its-kind project will create a network of charging and hydrogen fueling stations and enable zero-emission trucking from Mexico to Canada, linking ports and major freight centers in California, Oregon and Washington,” Rep. Pete Aguilar (D) and other lawmakers said in a letter last year to Transportation Secretary Pete Buttigieg.

The West Coast Truck Charging and Fueling Corridor is seen as complementary to the $5 billion National Electric Vehicle Infrastructure (NEVI) formula program, which is also funded through the Infrastructure Investment and Jobs Act (IIJA). The NEVI program aims to establish EV charging networks throughout the U.S.

The IIJA provides $2.5 billion over five years for the Charging and Fueling Infrastructure program. The program funds projects on two tracks: charging and alternative fuel corridors and community charging.

Four other California projects are receiving Charging and Fueling Infrastructure funding, according to Padilla’s announcement. The awards are:

    • $15.1 million to the Fort Independence Indian Community for EV charging along U.S. Route 395, a designated alternative fuel corridor.
    • $15 million to the county and city of Los Angeles and the Los Angeles County Metropolitan Transportation Authority for 1,263 Level 2 chargers and eight DC fast chargers on curbside light poles, at community facilities and at park-and-ride lots.
    • $14.1 million to the San Francisco Bay Area Rapid Transit (BART) District to install Level 2 chargers at all BART-managed parking facilities.
    • $3.2 million to the Shingle Springs Band of Miwok Indians to install 70 EV charging stations on the reservation and along U.S. Route 50, a designated alternative fuel corridor.
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Cold Weather Standard Fails Second Ballot

A proposed reliability standard that would affect registered entities’ preparations for extreme hot or cold weather events was rejected by industry stakeholders for a second time last week, with some commenters criticizing the team behind the standard for failing to address their objections to the previous version.

The latest formal comment period for TPL-008-1 (Transmission system planning performance requirements for extreme temperature events) began July 16 and ended Aug. 22, slightly shorter than the standard 45 days. NERC’s Standards Committee authorized shortening the comment period at its meeting in March. (See NERC Standards Teams Pushing to Meet FERC Deadlines.) Stakeholders submitted votes over the last 10 days of the comment period.

A total of 314 industry stakeholders were part of the formal ballot pool, with 276 casting votes according to the industry segment they represent. Of these, 40 voted to approve the standard, while 200 voted against. One of the negative voters did not submit a comment, so it was not counted with the negative votes, while 36 stakeholders abstained.

After the results were weighted to account for segment participation, the standard received a vote of 18.17% in favor. A two-thirds majority is needed for approval. The final result represents a decline from the standard’s last ballot round that closed on May 3, when 37 voted for it and 216 against, for a weighted segment value of 18.69%.

Project 2023-07 developed TPL-008-1 in response to FERC’s Order 896, which directed NERC to submit a standard by December 2024 addressing performance concerns of transmission equipment in cold weather. The standard would require responsible entities to perform extreme temperature assessments based on benchmarks selected by them from a library maintained by the ERO for both extreme heat and extreme cold.

Entities also would be required to work with planning coordinators to develop a process for creating benchmark planning cases that include “seasonal and temperature dependent adjustments for load, generation, transmission and transfers to represent the selected benchmark temperature events.” In addition, responsible entities would have to develop corrective action plans when a benchmark planning case indicates their part of the grid cannot meet performance requirements for certain contingencies.

Criticisms of the standard in the first ballot included a lack of insight into the library of benchmarks to be used by entities when developing their extreme temperature assessments, and respondents in the second round asserted this still was not addressed. In a comment endorsed by several other stakeholders, Mark Gray of the Edison Electric Institute said the benchmark library “is being developed without industry review and approval, and as of this draft we continue to only have superficial insights into this library.”

In addition, Gray said, the latest draft “still does not contain any specific boundary limits that could guide responsible entities in their extreme weather assessments or otherwise limit what might be contained or added to the extreme weather event library, now or in the future.” Gray suggested adding language identifying data that entities could use — such as meteorological data for the past 20 years, or extreme temperature conditions with a specified probability within an entity’s area — while “intentionally [leaving] the specific boundaries to be set by the” drafting team.

Respondents also expressed dissatisfaction with the team’s changes to requirements R3 and R4, which outline how PCs are to coordinate with entities on the development of benchmark planning cases. John Brewer, writing on behalf of the National Energy Technology Laboratory, said the standard is unclear about who will decide which entities can participate in benchmark planning studies, and how conflicts will be resolved if PCs select different benchmark temperature events.

Jennifer Weber, writing for the Tennessee Valley Authority, recommended that designated study entities “be identified as part of the PC developed coordination process” in order to reduce confusion over how they are to be chosen. In addition, she argued that a section of R4 that “requires an increasingly more extreme scenario for purposes of a sensitivity analysis” is not credible, especially when applied to longer-term planning horizons when information about generation additions and retirements is not known.

The next comment and ballot period for TPL-008-1 has not been determined yet. However, the standard drafting team for Project 2023-07 is scheduled to meet Aug. 29 to consider the comments received in this round.

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PJM MRC/MC Briefs: Aug. 21, 2024

Stakeholders Reject Revised Cost of New Entry Inputs

VALLEY FORGE, Pa. — Consumers and electric distributors in PJM last week opposed a proposal to revise two financial parameters used to calculate the cost of new entry (CONE) input to the 2027/28 Base Residual Auction (BRA). (See “PJM Proposes Increased CONE Parameters,” PJM MRC Briefs: July 24, 2024.) 

The measure would have increased the after-tax weighted average cost of capital (ATWACC) from 8.85% to 10% and set the bonus depreciation rate at 0% for the 2027/28 delivery year, rather than the 20% set through the Quadrennial Review. PJM and its consultant Brattle Group argued that the change would reflect higher costs typical PJM market participants face would face to borrow the capital necessary to construct the reference resource, a combined cycle generator. 

The Markets and Reliability Committee rejected the increase during its Aug. 21 meeting, with only 57.46% sector-weighted support, short of the two-thirds threshold. End-use customers and electric distributors were each 93% opposed, while transmission and generation owners unanimously supported the proposal. The Other Suppliers sector supported the change with 75% support. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said each of the parameters feeding into the variable resource requirement (VRR) curve interacts with each other, and that pulling individual pieces out for after-the-fact modifications would undermine the purpose of the holistic Quadrennial Review. 

He said consumer advocates would have concerns with the proposal regardless of the direction it shifted the parameters in, but they would be amplified when costs would increase at a time when capacity auction prices are reaching new highs. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

Carl Johnson, of the PJM Public Power Coalition, said it’s unclear how complete the review that Brattle conducted was and whether its ATWACC values would accurately reflect developer costs given the spike in capacity prices. He also argued there’s a disconnect between the reference resource used in the Quadrennial Review and the resources that have been proposed for construction through the interconnection queue, which is largely composed of renewables and storage. 

“It’s pretty clear that the reference resource doesn’t exist in the queue and making a change … that can only drive the price up doesn’t make sense,” he said. 

John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), questioned whether PJM has considered pausing the proposal given how close the entire region came to clearing at point “a” on the VRR curve, which results in the price cap being reached at 1.5 times net CONE. Two regions, BGE and Dominion, hit the price cap in the auction because of insufficient internal generation and transmission constraints. 

PJM’s Skyler Marzewski said the RTO’s focus is on ensuring that the parameters accurately reflect the costs to construct the reference resource and that the change would further that aim. 

Calpine’s David “Scarp” Scarpignato said price signals should be determined through the balance of supply and demand — a balance that would be disrupted if stakeholders write auction rules with a target price in mind. An accurate CONE value prompts not only new generation development, but also encourages existing generation to remain in the market, potentially by investing in upgrades that bring new supply online, he said. 

Stronger Know Your Customer Checks Endorsed

Stakeholders endorsed by acclamation a proposal to expand the data PJM collects when conducting due diligence checks on key leadership among its members through its Know Your Customer (KYC) process. The proposal was also endorsed by the Members Committee as part of its consent agenda. (See “Vote on Enhanced Know Your Customer Deferred,” PJM MRC Briefs: July 24, 2024.) 

The proposal would expand the tariff definition of member principals subject to KYC to include beneficial owners, which are a “natural person who, directly or indirectly, alone or together with such person’s family members, owns, controls or holds with power to vote 10% or more of the outstanding securities in the participant.” 

Members would be responsible for providing a list of principals meeting the new definition and supplying government-issued identifications. Individuals holding seats on boards of directors would also need to be identified under the changes. The effort is currently focused on PJM members that are not publicly traded, and therefore not required to report ownership information to the U.S. Securities and Exchange Commission. 

Since the June 27 first read of the proposal, language was added to specify that ownership split across family members includes spouses, domestic partners, parents, children and siblings. The principal definition was also revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. The vote on the changes was originally scheduled for July 24, but that was deferred to allow stakeholders to review the changes more thoroughly. 

The proposed definition of “principals” also was revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. PJM Assistant General Counsel Eric Scherling said the change is meant to address feedback that the definition could be too broad and capture staff with day-to-day operational control over assets. 

Stakeholders Greenlight 2 New Energy Market Parameters for DR

The MRC endorsed by acclamation a proposal to add two energy market parameters for demand response resources in the day-ahead and real-time markets. The changes are set to go before the MC during its Sept. 25 meeting. (See “New Economic DR Parameters Discussed,” PJM MRC Briefs: July 24, 2024.) 

The maximum down time would allow DR providers to define a “maximum number of continuous hours” for resource commitments, while the minimum down time would require a defined number of hours to pass between deployments. 

The proposed Manual 11 language states that the new energy market parameters do not override any capacity market obligations on the same resource. Independent Market Monitor Joe Bowring repeatedly voiced concerns throughout the stakeholder process that without such language, it may not be clear to market participants that they would be subject to Capacity Performance penalties if they followed their energy parameters and curtailed instead of remaining online according to a capacity deployment. 

During the Aug. 21 meeting, Bowring said the proposal would improve DR flexibility and more accurately reflect its capability in the PJM markets, but he argued it should be one small change in a larger consideration of DR’s role in the market. Bowring noted DR’s inability to be dispatched on a nodal basis, which he argued is critical for it to be an effective resource. 

PJM Discusses 2025/26 Auction Results

Changes to planning parameters and a redesign of components of the capacity market drafted through the Critical Issue Fast Path (CIFP) process last year were driving factors in the increase of capacity prices in the 2025/26 BRA, according to an analysis the RTO presented to the MRC. (See PJM Market Participants React to Spike in Capacity Prices.) 

PJM’s Tim Horger said the revised planning parameters led to the installed reserve margin (IRM) increasing because of load forecast uncertainty, the price cap being redefined from 1.5 times net CONE to gross CONE, a decrease in net CONE from $293/MW-day to $229, and the peak load forecast increasing by 3,243 MW. 

PJM’s Patricio Rocha Garrido said part of the impetus behind the planning changes was to identify and incorporate potential correlated outage into risk modeling. Following the December 2022 winter storm (“Elliott”), PJM also abandoned its practice of excluding the 2014 polar vortex data from risk modeling. 

Dominion Energy participating in the Reliability Pricing Model, rather than using the fixed resource requirement (FRR) alternative, also pushed supply and demand closer together, Horger said. 

The most significant CIFP changes were a requirement that generation owners planning to complete projects ahead of the start of the 2025/26 delivery year submit a binding notice of intent in order to offer into the auction; reliability risk modeling that captured more extreme weather, particularly winter storms; and marginal effective load-carrying capability (ELCC) for resource accreditation. 

The results of the changes were lower accreditation for many resources, meaning they could offer less supply, and more capacity being required to meet reserve margins. Horger said only 43 MW of capacity did not clear in the rest-of-RTO region, and the auction cleared 660 MW over the reliability requirement, compared to 7,754 MW in the prior auction. 

“Pretty much everyone who offered in the auction cleared,” he said. 

PJM Vice President of Market Design and Economics Adam Keech said most of the factors tightening supply and demand would have occurred regardless of the CIFP changes. About 16 GW of excess unforced capacity (UCAP) was available in the 2024/25 auction, of which 12 GW were lost because of generation deactivations, higher expected peak loads and the increased IRM. The CIFP changes are credited with reducing available UCAP by a further 2.7 GW.  

“There’s a lot of moving parts before we even get there that have an impact on the supply and demand balance on the system,” he said. 

Keech defined excess capacity as the total supply offered into the auction minus the reliability requirement. The UCAP values in the analysis were measured according to the rules for the 2024/25 auction. 

He said some of those dynamics are on track to continue in the 2026/27 BRA, for which the load forecast and reserve requirement are set to increase. That auction will be the first to use a combined cycle unit as the reference resource, which carries a gross CONE 55% higher than the combustion turbine used in past auctions. A higher CONE value could lead to the price cap also being higher. 

“We’ve got a tight system and one where the demand for capacity is going up,” he said. 

Bruce Campbell, of Campbell Energy Advisors, said the CIFP changes led to an administrative degradation of DR capability through the implementation of marginal ELCC accreditation, the effect of which remains unclear to many stakeholders a year after an endorsement vote on the approach. In the future, he said the Board of Managers should hold PJM accountable for providing more transparency regarding capacity market changes to reverse a history of DR being treated as an afterthought in market design. 

PJM CEO Manu Asthana said DR played a critical role in ensuring that the RTO met its reliability requirement in the 2025/26 auction. 

Susan Bruce, of the PJM Industrial Customer Coalition, said there is little time for new generation to come online ahead of the 2026/27 auction, which is scheduled to be conducted in December. Given that short timeline, she said DR could play an especially large role if market rules recognize its full value, especially for industrial loads in the winter that are less sensitive to weather than residential load. 

Bowring argued DR ELCC values are overstated because of assumptions about performance that are not supported by the data. He said DR is playing an increasingly pivotal role in the capacity auction — meaning that the auction would not have cleared reliably without DR — and argued that the exercise of market power by DR is correspondingly becoming a growing concern that will need addressing. 

He said the Monitor is planning to publish its own analysis on the 2025/26 auction as it does not agree with all the conclusions PJM has drawn, including the assertion that the prices primarily reflected changes in supply/demand fundamentals. 

Bruce said one of the goals underlying the CIFP changes was to create a market signal that would slow thermal deactivations, but one of the major causes of the high prices in the 2025/26 auction was coal, gas and oil deactivations. 

Keech said some resources were already planning to retire, while others are in a stage of their deactivation that they still have an ability to re-enter the market. 

PJM Proposes Sunsetting Electric Gas Coordination Senior Task Force

PJM brought a proposal to close the Electric Gas Coordination Senior Task Force (EGCSTF) and continue efforts to harmonize how PJM’s markets interact with gas supply through existing working groups, such as the Reserve Certainty Senior Task Force (RCSTF) and a possible new subcommittee with more flexibility in its scope. 

Susan McGill, PJM senior manager of strategic initiatives and chair of the task force, said the group’s working areas were completed when stakeholders endorsed a proposal to align day-ahead energy commitment cycles with the daily gas nomination deadlines in order to give gas generators more certainty on when they should procure fuel. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.) 

The task force was envisioned to spend a year working toward proposals, a timeline that was extended after Elliott. 

Hourly Notification Times

PJM’s Joe Ciabattoni presented proposed revisions to the tariff, Operating Agreement and Manual 11 to use hourly notification times when considering unit commitment in the day-ahead market. 

Hourly notification times can only be used in the real-time market, leading to discrepancies in reserve eligibility and capability when resources are offline, Ciabattoni said. 

The RTO intends to bring the proposal for endorsement votes during the Sept. 25 MRC and MC meetings, with a targeted implementation date on Dec. 1. 

First Reads on Several Manual Revision Packages

PJM presented first reads on three sets of revisions to Manual 6: Financial Transmission Rights, Manual 14B: PJM Region Transmission Planning Process and Manual 15: Cost Development Guidelines. 

The Manual 6 revisions would add a deadline for auction revenue right (ARR) trades on noon ET of the business day before the relevant auction opening and a deadline for relinquish requests on noon of the business day prior to the opening of stage 2 of the annual ARR allocation. 

The revisions also would disqualify transmission customers with firm services to charge energy storage or hybrid resources from receiving an allocation of ARRs to conform with FERC orders (ER19-469 and ER22-1420). (See RTOs Move Closer to Full Order 841 Implementation.) 

The changes to Manual 14B would revise the inputs to the light-load case that the RTO uses in its Regional Transmission Expansion Plan load forecast. (See “Manual 14B Revisions Include Change to Light Load Model,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

The case is meant to reflect load growth with flat profiles unaffected by weather and season by scaling load down to 50% of the summer forecast peak using bus-level data provided by transmission owners. PJM’s Stan Sliwa said the growth of non-scaling load, such as data centers, is changing how load shifts over the course of the year. The revisions would remove non-scalable load from the light-load case. 

The Manual 14B changes would also expand the NERC Transmission Planning standards examined during generator deliverability analysis to match current practice, updating the system operating limit definition and adding new standards created by the ERO. 

The Manual 15 revisions are aimed at correcting formulas throughout the manual and would remove a table displaying variable operations and maintenance (VOM) costs. Pulling the table from the manual is intended to avoid giving the impression that the values are fixed; the manual would instead point to the PJM website, where the VOM costs are updated annually to account for inflation. (See “Several Corrections to Formulas Included in Proposed Manual 15 Revisions,” PJM MIC Briefs: Aug. 7, 2024.)