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October 30, 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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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.) 

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Single Western Market Best for Reliability Needs, Panelists Say

A single Western market is one of the safest bets to address the region’s reliability and cost issues in the face of extreme weather events, proponents of the West-Wide Governance Pathways Initiative said during a panel discussion Aug. 22. 

Representatives from CAISO, Western Freedom and California Strategies participated in a webinar hosted by the Climate and Energy Policy Program at the Stanford Woods Institute for the Environment. The panelists discussed the findings of a new report issued by the institute, which found, among other things, that expanding cooperation in the West through a single market footprint could reduce the number of hours at risk for outages by as much as 40% during a monthlong, high-stress condition. 

The report examines the reliability impacts of three market configurations: two in which the Western Interconnection is divided into two separate RTOs with different footprints and one consisting of a single RTO comprising 11 Western U.S. states and the Canadian provinces of Alberta and British Columbia.  

It comes as the Pathways Initiative works to advance efforts to grant the Western Energy Markets (WEM) Governing Body increased authority over CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). The initiative also plans to establish an independent Western “regional organization” (RO) that would eventually assume more of the ISO’s market functions, including exercising sole authority over decisions related to the two interstate markets. (See California Energy Officials Pitch Pathways Plan to State Senators.) 

Stacey Crowley, CAISO vice president of external affairs, argued Aug. 22 that recent events, such as the Jan. 12-16 cold snap, showcased the WEIM’s ability to find energy and transfer it to where it was needed in the West. (See WEIM Q1 Benefits Report Adds to NW Cold Snap Debate.) 

However, “there is deeper coordination that could occur to assist with reliability in the long term, either long-term transmission planning and resource planning that recognizes the benefits of that large geographic footprint and the diverse resources that we have,” Crowley added. 

Marybel Batjer, partner at California Strategies LLC and former president of the California Public Utilities Commission, said an RTO is one of the few tools available to address increasing transmission costs and wildfire mitigation efforts in the West. 

“It’s already been proven with the EIM that we have a cost savings throughout the West, and it’s only by these regionalized efforts, if you will, that we can perhaps hold down the ever-increasing costs borne almost entirely by the ratepayer,” Batjer said. 

With states having different priorities, the initiative’s Launch Committee has worked hard to keep the Pathways proposal nonpolitical, according to Kathleen Staks, executive director of Western Freedom and co-chair of the Pathways Initiative. Staks noted that the committee has strived to build a governance structure that “respects each individual state’s ability to set its own energy priorities and its own energy goals.” 

Staks said reliability and affordability are the two primary nonpolitical drivers of the initiative. 

“Keeping the power going and having a reliable system is fundamental to survival and to our economy,” Staks said. “And so I think that is something that really is a transcending priority across all the 11 Western states.” 

Staks also pointed out that current regionalization efforts have attracted interest from data centers and other tech businesses with aggressive clean energy goals to set up shop in the West. 

“They need to be able to access a much bigger footprint of zero-carbon resources than they are probably able to get from any one sort of small utility footprint,” Staks said. “So, for them, this is a really important part of the reliability, affordability and sustainability. It really hits all three of those goals.” 

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Proposal to Limit Participation at New Hampshire PUC Spurs Backlash

New rules proposed by the New Hampshire Public Utilities Commission would “unduly exclude” companies and organizations from participating in its proceedings, according to a coalition of power generators, consumer advocates and environmental organizations.

The comments came in response to a pair of initial proposals that would overhaul how the commission undertakes proceedings. The proposals are intended to codify the delegation of responsibilities between the PUC and the state’s Department of Energy, which was established in 2021 (DRM 24-085, DRM 24-086). (See NH Poised to Merge Utility Regulator into New Dept. of Energy.)

The proposals drew widespread backlash for changes that appear to limit which organizations can participate in PUC proceedings. The concerns stem from how the new proposed rules would define an organization’s “standing” to participate in a proceeding. The groups wrote that the proposed definition — which limits standing to parties that face “direct injury” as the result of the proceeding — is “far too restrictive.”

“The proposed rules might bar many parties, like those in this joint letter, with clear, substantial interests; legitimate grounds for intervening; expertise on certain matters before the commission; and a long history of constructive participation in commission proceedings,” the groups wrote.

The changes could conflict with New Hampshire laws regarding intervention in utility proceedings, the coalition wrote. It proposed eliminating the definition of standing from the new rules, arguing that it is unnecessary.

“Because the proposed rules would drastically change the nature of commission proceedings, we urge the commission to engage in a more deliberative process before taking any action to finalize these rules,” the groups added.

The New England Power Generators Association (NEPGA) highlighted the “extraordinary coalition” that signed the joint comments, including the Conservation Law Foundation, the Consumer Energy Alliance and the Community Power Coalition of New Hampshire.

“This is pretty simple right vs. wrong in how these regulatory dockets should function,” NEPGA wrote in a statement. “We hope the New Hampshire PUC recognizes the error of this proposal and rethinks how dockets are dealt with for the benefit of all.”

The New Hampshire Office of the Consumer Advocate (OCA) raised similar concerns in comments submitted to the PUC in July, writing that standing to participate in a proceeding “should simply not be defined in the commission’s rules” and that the definition included “is vastly too narrow.”

The OCA also expressed concern that the proposed rules “seek to appropriate a significant degree of policymaking authority to the commission that rightfully belongs to the Department [of Energy].” The proposed changes would shift the PUC toward “a paradigm in which the tribunal and its presiding officer are not simply neutral decisionmakers but are also assuming a prosecutorial role,” it said. Increasing the role of the PUC in the discovery and development of evidence could undermine its statutory role as a neutral arbiter while deciding cases, it added.

The office also urged the commission to use the rulemaking as an opportunity to promote transparency in public utility proceedings, arguing that information submitted by utilities in PUC proceedings is frequently treated with a broad stamp of confidentiality.

“We respectfully suggest a reexamination of the assumptions underlying confidential treatment of commission records, a subject of particular interest to the OCA because our enabling statute requires us to maintain the confidentiality of all information so designated by the commission in adjudicative proceedings,” the office wrote.

Concerns about the rulemaking appear to be shared by the state’s utilities. At a public hearing on the proposal in July — which was not attended by the PUC commissioners, according to testimony by the OCA — Eversource Energy requested a “a more collaborative and participatory process.”

“The changes proposed by the commission are substantial and extensive,” said David Wiesner, Eversource senior counsel. “Some are long overdue and welcomed logistical updates to account for the creation of the Department of Energy, while others are significant revisions or entirely new procedures altogether that would change core regulatory processes that currently exist.”

A representative of Unitil echoed these comments and added that the rules limiting who can participate in proceedings appear to be “essentially unconstitutional.”

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Court Sides with PG&E in Long-running San Francisco Dispute

The D.C. Circuit Court of Appeals on Aug. 23 ruled in favor of Pacific Gas and Electric (PG&E) in the latest twist in a nearly two-decade dispute with San Francisco over a distribution system wheeling contract between the two entities (No. 23-1041).  

At issue in the case, which was remanded back to FERC, is PG&E’s application of its wholesale distribution tariff (WDT) to the municipal electricity customers of the San Francisco Public Utilities Commission (SFPUC), a city-operated utility. (See FERC Refuses Rehearing of PG&E-San Francisco Dispute.) 

SFPUC, which operates a hydroelectric project in California’s Hetch Hetchy Valley, supplies electricity to individual consumers, schools, public housing tenants, libraries and municipal departments using the distribution system PG&E owns and operates in San Francisco — making it both a customer and competitor of PG&E.  

Since 2014, San Francisco has argued to FERC that PG&E has unreasonably denied distribution to many of SFPUC’s approximately 2,200 metered delivery points, under section 212(h) of the Federal Power Act. 

That section prohibits forcing a utility such as PG&E to deliver another utility’s power through its distribution lines, but it also exempts cities and counties where “such entity was providing electric service to such ultimate consumer” on the date the subsection was enacted: Oct. 24, 1992.  

PG&E has countered that it wasn’t obligated to provide service to any delivery point where SFPUC didn’t provide service as of October 1992. 

In 2019, FERC issued an order disagreeing with an initial decision by a FERC administrative law judge (ALJ) who had supported San Francisco’s argument by citing the commission’s November 2001 orders under Suffolk County Electric Agency (96 FERC ¶ 61,349). In that set of decisions, FERC said section 212(h) grandfathered classes of customers, not individual customers at specific delivery points. 

In overruling the ALJ, FERC’s 2019 order found Suffolk to be inapplicable to the San Francisco dispute and said PG&E had not been unreasonable in denying service to some SFPUC customers. The commission found that PG&E’s “point of delivery” approach to determining which customers were entitled to service under the WDT was just. 

In January 2022, the D.C. Circuit reversed FERC’s 2019 ruling, sending the case back to the commission on remand after finding that the WDT’s reference to “points of delivery” does not imply that only specific points of delivery may be grandfathered under the agreement. 

In its October 2022 order on remand, the commission followed the court’s direction and agreed with the city that FERC’s precedent didn’t limit grandfathering to a fixed location, concluding that any of San Francisco’s load associated with “customer classes” being served on Oct. 24, 1992, were entitled to grandfathered service under the WDT.  

The commission in March 2023 rejected PG&E’s request for a rehearing (EL15-3). 

‘Ultimate Consumer’

But the D.C. Circuit’s Aug. 23 ruling vacated the October 2022 order and again remanded the case back to FERC.  

PG&E’s petition to the court focused on the FPA’s definition of an “ultimate consumer” and the risks to PG&E of FERC conflating that concept with “customer class.” The utility argued that the commission’s October 2022 ruling would force it to use its facilities “to serve a potentially unlimited number of [future such] customers” and that it must “incur … costs to acquire and maintain the facilities necessary to serve those customers.” 

PG&E further contended that FERC’s “broad class-based” interpretation of the WDT’s grandfathering clause could not be reconciled with the plain meaning of “ultimate consumer” under the FPA. 

The court agreed, finding that FERC “cannot order PG&E to wheel electricity to ‘an ultimate consumer’ of SFPUC unless SFPUC ‘was providing electric service to such ultimate consumer on Oct. 24, 1992.”  

“Considering the text and structure of section 824k(h)(2), as well as the broader statutory context, we conclude that ‘ultimate consumer’ does not refer to an atextual class or group of consumers,” the court found. “FERC’s orders are therefore contrary to law.”   

FERC “must apply the plain meaning of [FPA] section 824k(h)(2) consistent with this opinion and determine which of SFPUC’s consumers qualify for wheeled service under” the WDT, it concluded.