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August 29, 2024

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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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State Briefs

FLORIDA 

PSC Approves Duke Energy Rate Increase Settlement

The Public Service Commission has approved a settlement to raise Duke Energy’s base rates by $203 million in 2025 and $59 million in 2026. Duke originally sought a $503 million increase in 2025, $98 million in 2026 and $129 million in 2027. As part of the settlement, Duke will recoup costs from customers for 12 new solar facilities. The solar increases are projected to total $12 million in 2025, $71 million in 2026 and $58 million in 2027, the utility said. 

More: WUSF 

GEORGIA 

PSC Clears Path for Georgia Power’s New Fossil Fuel-burning Units

The Public Service Commission voted to certify the cost to build three new oil and gas-burning units Georgia Power says are needed to meet demand. 

The PSC already gave Georgia Power a green light to skip the normal competitive bidding process to expand Plant Yates but did not sign off on its estimated capital and construction costs. The vote now sets a cap on the costs that customers are likely to be charged down the line. 

Running on natural gas, the three units will have a combined maximum output of 1,300 MW. Powered by diesel, their capacity drops to 1,070 MW. 

More: The Atlanta Journal-Constitution 

INDIANA 

CenterPoint Energy Fined for Federal, State Pipeline Violations

CenterPoint Energy has agreed to pay a penalty of nearly $2 million to the state of Indiana for violations of federal pipeline law. The utility will pay $1,997,500 to the state’s general fund, none of which can be recovered through customer rates, according to the Utility Regulatory Commission. CenterPoint violated federal and state pipeline safety standards under the Natural Gas Pipeline Safety Act, the Hazardous Liquid Pipeline Safety Act and state code. 

More: Evansville Courier & Press 

NIPSCO Brings Solar Project Online

NIPSCO has announced its 200-MW/45-MW Cavalry solar and storage project has become operational. Cavalry is the third solar project in NIPSCO’s generation portfolio. The other two — Indiana Crossroads and Dunns Bridge I — already are operational, with a combined generation capacity of 465 MW. 

Elsewhere in the state, CenterPoint Energy issued a request for proposals seeking applications for renewable and thermal energy projects. 

More: PV Tech 

LOUISIANA 

PSC Approves Entergy Rate Hikes

The Public Service Commission has approved two settlements with Entergy to raise customers’ rates. Starting in September, Entergy customers will see an annual increase of about 2% ($4/month). Entergy Gulf States customers will see an increase of 3%. Entergy also agreed to reduce late fees from 5% to 1.5%, a 70% reduction. 

More: WWNO 

MASSACHUSETTS

Holtec: No State Authority to Ban Radioactive Water Discharge into Bay

Holtec International, the company that was denied a permit to release nearly 1 million gallons of water from the nuclear reactor system at Pilgrim Nuclear Power Station as part of its decommissioning, has filed an appeal seeking to discharge the radioactive water into Cape Cod Bay. 

Holtec’s appeal hinges on two main ideas: one, that discharge of water from Pilgrim is grandfathered under state law; and two, that federal law preempts state decisions on nuclear waste. The company argues that Massachusetts cannot completely bar the release of radioactive material because that authority lies with the federal government. 

The appeals office within the Department of Environmental Protection — the same agency that denied the permit — is the final venue for administrative appeal before the matter could go to court. 

More: WBUR 

MONTANA 

PSC Asks for More Information from NorthWestern Regarding Rate Request

The Public Service Commission said that while NorthWestern Energy provided additional information about its pending rate increase request, the utility still has not adequately explained its “cost of service” studies, or how it allocates costs among different types of customers. 

PSC President James Brown said the commission can’t move ahead until NorthWestern complies with the law and provides more information. NorthWestern seeks an 8.3% increase for a typical residential customer and a 17% increase in natural gas costs, although the utility also requests smaller interim increases effective Oct. 1. 

More: Daily Montanan 

NEBRASKA 

Lincoln Board Declares County ‘Nuclear-friendly’

Lincoln County commissioners voted 5-0 to declare Lincoln County “nuclear-friendly” as the Nebraska Public Power District begins to identify locations to upgrade its nuclear capacity. The NPPD recently announced a feasibility study of 16 locations to install small modular reactors. The board’s resolution says the technology “has the potential to vastly extend the lifespan of Gerald Gentleman Station and its economic impact on Lincoln County.” 

More: The North Platte Telegraph 

OPPD Transitioning Omaha Coal Plant to Natural Gas

Omaha Public Power District CEO Javier Fernandez said the company will transition the north Omaha coal plant to natural gas by 2026. Along with the transition, Fernandez said the plant will retire three other units. The plan still needs approval from SPP.

More: KETV 

NEW HAMPSHIRE

Lawsuit Challenges Ability to Rebuild Tx Lines, Charge Ratepayers

A lawsuit filed in U.S. District Court claims federal and regional regulators failed to follow regional planning requirements and exempted large transmission projects from the planning process. 

The suit names FERC, ISO-NE and Eversource and seeks compensatory damages, court and other legal costs, and an injunction to stop the rebuilding of the 49-mile, X-178 transmission line between Whitefield and Campton. While the suit is the first legal action on the project, others have raised concerns about “asset condition” projects that allow utilities to rebuild or rehabilitate existing transmission lines and charge New England ratepayers for the cost with little or no scrutiny to determine long-range needs and costs. 

The $385 million project would be a “complete rebuild” and replace existing wooden towers with larger metal structures. The plaintiffs claim the work would exceed the terms of the 1948 easement over the land. 

More: InDepthNH 

NEW YORK

Bitcoin Company Sues State for Denying Air Permit

Greenidge Generation filed a lawsuit claiming the Department of Environmental Conservation exceeded its authority by declining to renew the facility’s air permit because it could not comply with greenhouse gas limits that will be phased in through 2050. 

The agency ordered the natural gas plant to cease operations on Sept. 9. In 2023, the plant emitted nearly 800,000 tons of carbon dioxide. 

The complaint notes the plant provides “a significant amount of electricity behind-the meter to a cryptocurrency mining operation.” Greenidge brought in $32.4 million for its bitcoin-mining operations in the first six months of this year. In July alone, the company mined 58 bitcoins, valued close to $3.5 million, according to financial documents. 

More: Gothamist 

OHIO 

PUC OKs $100M in Consumer Subsidies for 2 Coal Plants

The Public Utilities Commission approved more than $100 million in subsidies from 2020 by customers to pay for the operation of two coal-fired power plants that were part of the state’s HB6 scandal.

The PUC affirmed the findings of an auditor that the $105 million in charges collected by AEP Ohio, Duke Energy Ohio and AES Ohio were appropriate. Commissioners also found in four other cases that subsidies that date back to 2016, before HB6 became law, were proper. 

More: The Columbus Dispatch 

RHODE ISLAND

Portsmouth LNG Facility to Remain Active for 5 More Years

The Energy Facility Siting Board has approved Rhode Island Energy’s application to extend the life of the Portsmouth LNG storage facility for the next five years. The facility opened five years ago as a temporary backup to Aquidneck Island’s gas delivery system. As part of the decision, the board also requires the utility to reduce natural gas demand on the island. 

More: Providence Journal 

SOUTH CAROLINA

Santee Cooper Buys Land for Future Generation

Santee Cooper has announced it will buy more than 150 acres in Hampton County, possibly for a future power plant. 

A legislative oversight panel signed off on the company’s $3.2 million land purchase. The site, located in an industrial park, is a backup plan for the utility if it’s unable to partner on a proposed natural gas-fired plant with Dominion Energy in Colleton County. While Santee Cooper is considering the Hampton County land as a secondary option, CEO Marty Watson said the land would have “no specific designated use” at this time. 

More: South Carolina Daily Gazette 

TEXAS 

Judge Denies CenterPoint’s Motion to Withdraw Rate Request

An administrative law judge has denied CenterPoint Energy’s motion to withdraw its pending request to increase rates.

CenterPoint filed an application in March to increase its portion of the average residential monthly bill by $1.25. The company filed a notice to withdraw the request in August after withering criticism over its preparation and response to Hurricane Beryl.

CEO Jason Wells said the company wanted to focus on immediately improving its operations during this hurricane season. However, consumer advocacy groups and municipalities, including the city of Houston, countered that if approved, the withdrawal would deny them the chance to “claw back” certain expenditures. 

The judge’s ruling is final unless it is appealed to the Public Utility Commission. Without a withdrawal, CenterPoint’s pending application is paused as it engages in settlement discussions with cities and advocacy groups. 

More: Houston Chronicle 

VIRGINIA 

Dominion Moving Proposed Chesterfield Gas Plant

Dominion Energy says it’s moving the gas-fired power generators it wants to set up in Chesterfield County to the site of its existing power station by the James River. 

Dominion initially proposed building the new facility on land next to its Chesterfield Power Station in the James River Industrial Park site. The utility said it decided to change the location based on interactions with the community. 

The four new natural gas units will have a combined capacity of 1 GW. 

More: Richmond Times-Dispatch 

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Company Briefs

GE Vernova Reports 2nd Blade Failure at OSW Project in England

GE Vernova has reported a second “blade failure” on one of its installed Haliade-X turbines at the Dogger Bank wind farm off the coast of England, raising new concerns about a turbine that experienced breakdowns twice before. 

The first incident at Dogger Bank occurred in May, although the company said it was an “isolated event” caused by improper installation. However, a second failure occurred in mid-July at the Vineyard Wind farm. A GE Vernova spokesperson in an email statement said the latest Dogger Bank failure on Aug. 22 was an “isolated blade event that occurred during commissioning” and that no injuries occurred. 

More: The New Bedford Light 

PG&E Racing to Stem Increasing Fires Ignited by Power Lines

Pacific Gas and Electric has reported 62 ignitions in high-threat fire areas to the California Public Utilities Commission so far this year, compared with 65 for the entirety of 2023, according to company executives. 

Twenty-nine of those occurred in August after an early July heat wave that set record temperatures throughout the state and dried out grasses and brush, making them more likely to catch on fire. “The data that we’ve been looking at is concerning,” said Mark Quinlan, PG&E’s senior vice president of wildfire and emergency preparedness. “We’re reacting to that trend and trying to see what else PG&E can do to up the game.” 

PG&E established a task force to evaluate the problem and determine what could be done to address it quickly before the start of fall, when strong offshore wind patterns increase wildfire risk. The company has worked to clear vegetation from beneath about 50,000 utility poles and install equipment to better monitor power line disruptions. 

More: The Wall Street Journal 

Arch, Consol to Combine into $5.2 Billion Coal Giant

Arch Resources and Consol Energy have agreed to combine in an all-stock merger of equals to create a new $5.2 billion entity called Core Natural Resources. 

The companies said the merger would make a North American natural resources company with a focus on global markets, generating between $110 million and $140 million of annual cost and operational synergies. 

Under the terms of the deal, Arch shareholders would receive 1.326 shares of Consol stock for each Arch share they own, with Arch stockholders owning about 45% of the combined company, and Consol shareholders owning the other 55%. Core would have a market capitalization of about $5.2 billion, the companies said. 

More: The Wall Street Journal 

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Federal Briefs

States, Coal Companies Ask SCOTUS to Halt Biden Rule to Restrict Pollution

Twenty-three Republican-led states and at least two coal companies are asking the Supreme Court to halt a Biden administration rule that seeks to limit power plants’ emissions of mercury and other toxic metals. 

The states argue the rule could lead to grid issues if coal plants decide to shut down in response. If they don’t, the states said the rule will cause price increases. 

The rule in question tightens emissions limits for toxic substances such as lead and arsenic by 67%. For some coal plants with historically looser mercury controls, the rule tightens mercury limits by 70%. 

More: The Hill 

TVA to Boost Electric Rates by Largest Amount in a Decade

The Tennessee Valley Authority Board of Directors has voted to raise wholesale power rates by 5.25% on Oct. 1, adding $4.35 a month to the typical power bill.

The increase, which will help TVA raise more than $500 million of extra revenue in the next year, follows a similar 4.5% wholesale rate hike adopted in 2023. However, President Jeff Lyash said after this rate hike, the utility hopes to avoid any further rate increases for at least the next three years. 

It is the largest raise to TVA’s wholesale rates for electricity in 16 years. 

More: Chattanooga Times Free Press 

BLM Seeks Public Input on Proposed Easley Solar Project

The Bureau of Land Management is seeking public comment on the draft environmental assessment for the proposed Easley Solar project in Riverside County, Calif. If approved, the project could generate up to 400 MW with 650 MW of storage capacity. The comment period closes Sept. 20. 

More: Bureau of Land Management

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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.)