Search
`
November 26, 2024

Posted on

NYISO Monitor Highlights Gap Between Planning, Market Requirements

NYISO’s transmission planning requirements result in a need for more capacity than is required in the ISO’s market rules, according to Potomac Economics, the Market Monitoring Unit.

Potomac highlighted the gap between what it calls the “effective planning requirement” for transmission security and capacity market requirements in a presentation before the NYISO Operating Committee on Oct. 24.

“The reliability planning process effectively requires more capacity to meet transmission security needs than is represented in the capacity market requirements that are ostensibly based on transmission security,” according to a memo Potomac sent to the ISO. For the 2025/26 capability year, Potomac said the effective requirement for New York City is 743 MW higher than its locational capacity requirement.

NYISO this month found a potential reliability need by 2033 for New York City, which would trigger a process in which the ISO solicits solutions from utilities and stakeholders, including non-market interventions. (See NYISO Draft RNA Finds Reliability Need for New York City.)

“Within the next five years, the base case assumptions become much more important when reliability needs appear,” Pallas LeeVanSchaick, vice president at Potomac, told the committee. “If there are not forthcoming market-based solutions, then there’s the potential to identify a need that requires an out-of-market investment to resolve it. That raises concerns.”

The MMU noted the 565 MW of peaking units retained in Brooklyn to address a reliability need identified in a Short-Term Assessment of Reliability in 2023. Despite that, the city is expected to have an over 800-MW surplus in summer 2025.

“Out-of-market actions to satisfy the planning requirements increase risk to investors by depressing capacity prices below anticipated levels,” it said.

LeeVanSchaick said that special-case resources — a type of demand response for large loads — were not being counted in transmission security analyses because they are only called upon in emergency conditions. Surplus capacity, he said, was being overcompensated in part because it was being set by the inflated transmission security floors.

“When SCR program resources also participate in peak shaving programs, the resulting load reductions are not counted towards satisfying the reliability need even though they occur during normal operations,” the MMU said. “This treatment significantly increased capacity shortfalls in the transmission security analysis of the RNA and inflates the transmission security limit for New York City by a comparable amount.”

The MMU recommended including loads participating in peak shaving and emergency DR programs in transmission security analyses and compensating capacity suppliers based on the requirements they contribute to meeting. It also repeated a previous recommendation that NYISO implement more granular capacity zones, particularly in places like New York City, and update them dynamically.

The OC voted to send the draft RNA to the Management Committee, though it changed the motion from an approval of the draft itself to an approval of its findings.

NYISO also presented the results of the 2024-2025 Winter Assessment, finding that the ISO expects sufficient winter capacity assuming that all firm fuel generation is available under both normal and extreme weather conditions. The ISO cautioned that disruptions in fuel supplies could create problems for the grid given the reliance on firm fuel generation during extreme cold weather.

Posted on

NJ BPU Approves EV Charging Station Rules for MHD Vehicles

In a much-anticipated move, the New Jersey Board of Public Utilities on Oct. 23 adopted minimum filing requirements that allow utilities to propose programs to promote the development of medium- and heavy-duty (MHD) electric vehicle chargers. 

The 4-0 vote approving the rules concluded a three-year process to craft a plan to fund and install MHD charging infrastructure that is either publicly accessible or used to set up private fleet charging depots. The plan allows utilities to award incentives totaling up to $55 million over two years for charging infrastructure projects that meet the criteria. 

State officials consider the availability of a heavy-duty charging system key to tackling the largest source of carbon emissions in the state: transportation. The goal is to motivate truck users to adopt electric vehicles by removing the fear that they will run low on power en route and won’t be able to find a recharge site. 

The approval follows the initial release of a “straw proposal” of rules June 30, 2021, and a second straw proposal Dec. 22, 2023. 

“I know this one was long and eagerly awaited,” BPU President Christine Guhl-Sadovy said after the vote.   

“A lot of work went into this by staff, by our partners, and certainly by stakeholders in their comments and discussions over the years,” she said. “I think we’re all really excited to see this, and I know relieved.”  

The vote came the same day that EPA Regional Administrator Lisa F. Garcia, New Jersey Department of Environmental Protection Commissioner Shawn M. LaTourette, and other federal and state officials gathered at a New Jersey Turnpike rest stop in Ridgefield to mark the receipt of $250 million in federal funds to install MHD EV chargers on the I-95 corridor. 

New Jersey and Connecticut, Delaware and Maryland, which make up the Clean Corridor Coalition, will install 450 charging ports at 24 sites along the highway. (See NJ To Install 167 Heavy Truck Chargers with $250M Federal Grant.) 

The BPU’s process, however, is separate from the highway projects, which won’t be affected by the BPU’s rules, spokesman Bailey Lawrence said. 

Anjuli Ramos-Busot, director of the New Jersey Sierra Club, called the approval a “huge milestone not only for clean transportation, but also for climate and clean air.”  

“New Jersey is one of the most densely populated states in the nation, and as such, our transportation sector is one of the dirtiest,” she said. “Electrifying fleets at a local and state level will directly benefit our communities who experience roadway pollution.” 

She added that “we are hopeful the utilities in the state will follow through with good programs to electrify our fleets and charging infrastructure that contain equity provisions.” 

Shared Responsibility

The rules make the four electricity utilities that serve the state — PSE&G, Jersey Central Power and Light (JCPL), Atlantic City Electric (ACE) and Rockland Electric Co. (RECO) — “responsible for the wiring and backbone infrastructure necessary to enable a robust number of MHD make-ready locations throughout the state.” Each utility must file a two-year MHD plan within 120 days of the order’s approval.  

The order describes a “shared responsibility model (that) will bring significant investment into MHD EV charging while protecting consumers and ratepayers, facilitating a smooth rollout of EV charging infrastructure.” 

Private infrastructure companies, site owners and industries will own, operate and install the chargers, and an industry working group will address emerging issues such as rate levels, demand chargers and other factors, including interconnection, local generation and storage issues, the order approved by the board states. 

Utilities can invest in and earn a return on backbone and infrastructure make-ready wiring for publicly accessible charging depots, those that serve public-serving fleets and government agencies. In each case, the utility can provide up to 100% funding, including offering incentives.  

Utilities also can invest in infrastructure that supports private fleet charging depots that are in overburdened communities or municipalities but can provide only up to 50% funding, including incentives, according to the rules. 

But utilities can own and operate MHD charging stations only in certain circumstances, according to the rules. That can happen if the proposed charging station is in an area of “last resort,” in which no private company has stepped up to install a charger for 18 months, and 24 months if the station is in an overburdened area, according to the rules. 

This “shared responsibility model will bring significant investment into MHD EV charging while protecting consumers and ratepayers, facilitating a smooth rollout of EV charging infrastructure,” according to the board order. 

The rules provide for PSE&G to award incentives up to $30 million, JCPL to award up to $15 million, and ACE and RECO to award up to $5 million each. 

“Providing more charging for electric delivery vans, trucks, school buses and transit buses, especially for public fleets, is the path forward to clean our air and clean our fleets,” said Doug O’Malley, director of Environment New Jersey. “This board action will help pave the way for an electric bus and truck future.” 

Posted on

NY Receives Largest OSW Proposal Yet

The newest crop of wind farm proposals off the New York coast includes the largest plan ever submitted there, or apparently anywhere else in U.S. waters. 

The latest iteration of Community Offshore Wind is a two-phase project that would reach peak output of up to 2.8 GW in the early 2030s.  

Community has a simultaneous 1.3-GW proposal under consideration by New Jersey regulators. (See 3 OSW Proposals Submitted to NJ.) 

Daniel Sieger, head of development at Community Offshore Wind, spoke recently to NetZero Insider about the evolution of the joint effort by RWE and National Grid Ventures and its direction from here. 

Community is not hedging by bidding different versions of the same project into two states at once, he said. It wants to send power to both. 

“We have a large lease area that can accommodate multiple projects,” Sieger said. “We’ll see how the process plays out with both New York and New Jersey, but right now, those are both active proposals.” 

Community Offshore Wind’s wind lease area is south of New York and east of New Jersey. | Community Offshore Wind

When Community won lease area OCS-A 0539 in the February 2022 New York Bight auction, the U.S. Bureau of Ocean Energy Management calculated the energy potential of its 125,964 acres conservatively at 1,387 MW. 

Community’s decision to propose up to 4,100 MW there reflects how far technology has evolved in the intervening three years and how much further it is likely to improve before the time comes to put steel in the water. 

“The full capacity is going to depend on turbine technology and permitting and will be done in consultation with state and federal officials,” Sieger said. “But we think that we have the possibility of three different phases of project development in our lease area.” 

The path to this point has been neither straight nor smooth: Community has struggled against the same headwinds that have affected the entire industry in the past two years. This latest proposal is its fifth attempt to land a contract. 

    • It nearly won a 1.3-GW contract in NY3, along with two other developers, but all three conditional contracts had to be scrapped when the GE Vernova halted development of the 18-MW turbine that would have made the contracts financially viable. (See NY Offshore Wind Plans Implode Again.) 
    • It submitted a 1.3-GW bid in NY4, a rush solicitation New York put together after the state’s offshore portfolio collapsed, but New York instead awarded contracts to two mature projects that could get steel in the water sooner. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.) 

Community now is awaiting the two states’ decisions on the combined 4.1 GW it proposed in NJ4 and NY5. 

The progress to date might seem frustrating, but it is not wasted time. Development continues even as a particular path ends or is rerouted; proposals are updated and reshaped through what has become an iterative process. 

“The project and the plans evolve as we go further into development and we mature the project,” Sieger said. “But this proposal that we have submitted here [to New York] I think is really well positioned for selection and well positioned to deliver.” 

Sieger joined Community shortly after the 2022 auction and has seen shifts as industry, state and federal leaders tried to push offshore wind forward through some strong headwinds in the past two years. 

Daniel Sieger, head of development for Community Offshore Wind. | Community Offshore Wind

“I think with any new industry, there’s going to be some ups and downs and some stops and starts,” he said. “But I think we’re really starting to see the industry mature here in the United States, to the point where we’ve got projects in operation in the United States, we’ve got projects under construction.” 

In its NY5 bid, Community says it would start generating power in 2030 and reach completion in 2032. That time frame should give it some breathing room to let offshore wind technology evolve and a U.S. ecosystem grow to support it. 

But there still is a chicken-and-egg balance to strike, in which enough projects are greenlighted far enough in advance to justify building ports and factories, and enough ports and factories are built soon enough to support those projects. The balance goes far beyond development in any one lease area, but Sieger said Community’s plans are big enough to help move the needle. 

“I think that as the offshore wind industry and market matures in the United States, we’re going to see a lot of opportunity for localization of the supply chain,” Sieger said. Their project is an opportunity for certainty in the market, “to sort of lock in that pipeline that’ll unlock some of the investment for some of these supply chain entities to localize.” 

Community still has not settled on a particular turbine model, port, installation vessel or many of the other critical pieces of building a wind farm. 

One of its most publicly visible efforts has been toward public visibility — engaging with the stakeholders and local residents who will influence the reception Community’s proposals receive and the ease with which they move through the review process. Its social media feeds are packed with examples. 

Community faces a potential public relations test with one of its possible export cable routes, which would run to the south shore of Long Island near a city that mounted strong opposition to Empire Wind 2’s proposal to use the same point of interconnection. (See ‘What Did We Do to Deserve This?’) That proposal was withdrawn recently, 27 months after it was launched. (See Equinor Yanks Request for Empire Wind 2 Export Cable.) 

Sieger did not discount the prospect of local opposition, but he did not seem daunted by it, either. 

“We have prioritized, since day one, active engagement on the ground with the communities where our project is going to be located,” he said. “As we enter into the permitting process and the siting process and the routing process, we intend to continue those conversations and work hand-in-hand with the local communities to determine the best route from the landfall to the point of interconnection.” 

Along the way, Community is working to recruit allies. In its NY5 proposal, it has committed to $64 million in workforce development, up to $250 million in manufacturing development, $121 million in community support and more than $67 million in fisheries assistance. It also has pledged to support organized labor, disadvantaged communities, minority/women/veteran-owned business and other priorities baked into New York’s offshore wind initiative. 

The projected cost of proposals submitted in NY5 by Community, Ørsted and Vineyard Offshore is likely to be substantial but will not be revealed until the state finalizes contracts, which is expected in the first quarter of 2025. 

One clue: Community Offshore Wind said its 2.8-GW proposal would drive roughly $3 billion in economic activity, more than $2 billion of it in-state spending. 

Posted on

Texas Public Utility Commission Briefs: Oct. 24, 2024

PUC Hears State’s First System Resiliency Plan, Filed by Oncor

The Texas Public Utility Commission postponed action on Oncor Electric Delivery’s resiliency plan, the first from a state utility under new legislation, during its Oct. 24 open meeting.

Commissioner Jimmy Glotfelty asked for more time before approving, modifying or denying Oncor’s three-year system resiliency plan. The commissioners — meeting without Lori Cobos, who was excused following a death in her family — agreed to postpone a decision until its Nov. 14 open meeting (56545).

“This proceeding is the first of its kind, and I would like to request additional time to consider the plan, the agreed modifications and Oncor’s responses to any questions from the commissioners,” he said in a pre-meeting memo.

Texas House Bill 2555 directed the state’s transmission and distribution utilities to strengthen the resiliency of their systems. Oncor said its resiliency plan is “comprehensive and forward-looking” to proactively withstand, mitigate or quickly recover from the “historical and evolving resiliency events” it expects to affect its system.

An administrative law judge approved the Oncor plan in September, finding it in the public interest.

Brian Lloyd, Oncor’s vice president of regulatory policy, told the PUC that a “constructive” settlement agreement with commission staff and several other parties gives the utility an opportunity to bring forward some of the plan’s spending into this year.

He said the utility mapped its entire distribution system against all extreme weather events since 1998, including extreme heat and cold, major storms and wildfires. Oncor has identified wildfire risk as a major threat to the distribution system; with much of Texas suffering from drought conditions, Lloyd appeared eager to put the plan into effect.

“We have had red flag days on our system this week,” he said. “The state is dry. We know that we are ready to go to further address that risk. As soon as you are comfortable with this, do so.”

Oncor said it’s limiting its recovery of the plan’s capital costs to $2.8 billion and another $521 million in incremental operations and maintenance expenses for 2024-2028. It will defer $309 million in capital costs and O&M expenses to a fourth system resiliency plan year.

Commission Delays Decision on CenterPoint

The PUC agreed to put off a decision on CenterPoint Energy’s attempt to withdraw a $60 million rate case until the commission’s next open meeting on Nov. 14 (56211).

PUC Chair Thomas Gleeson said he had been ready to reach a decision during the meeting but no longer was prepared to do so. He suggested to his fellow commissioners that they rule on CenterPoint’s request no later than the next open meeting.

“I still have some things I need to work through, because I’m still not sure which way to come down on this, honestly,” he said. “I think there are really good points on both sides.”

CenterPoint said withdrawing the rate case, originally filed in March, and refiling it next year would allow it to use 2024 as the test year. An administrative law judge denied CenterPoint’s request to withdraw the rate case in August. The utility then appealed the decision to the PUC.

Gleeson said that during a recent public hearing in Houston, residents expressed a desire for the PUC to evaluate CenterPoint’s performance during and after Hurricane Beryl. The Category 1 storm knocked out power to nearly 3 million customers in the Houston area. CenterPoint was castigated for its poor communications during a recovery effort that lasted more than a week. (See Texas Politicos, Residents Bash CenterPoint.)

“One way to [evaluate CenterPoint’s performance] is to allow them to withdraw this case and then force them to file sometime in 2025 with the 2024 test year, where we could hear evidence about performance during Beryl and their infrastructure improvements,” he said.

CenterPoint associate general counsel Patrick Peters told the PUC that allowing the utility to withdraw from the rate case would allow it to focus on its work improving resiliency and restoring public trust. He said the utility then would be able to incorporate its learnings from Beryl into a new rate case.

Politicians, including Houston Mayor John Whitmire, and several consumer groups have called for a rate decrease and oppose the withdrawal.

The commission also declined to act on CenterPoint’s proposed 138-kV line in a high-growth region north of Houston. The utility said the line is necessary to address the strained existing system, but it has run into opposition from local residents (55768).

At the same time, the PUC rejected CenterPoint’s settlement with commission staff, the city of Houston and the Gulf Coast Coalition of Cities to adjust the utility’s system-average interruption duration index (SAIDI) and system-average interruption frequency index (SAIFI). Gleeson said the utility’s continued use of a one-minute threshold for the next seven years is “incongruous” with improved technology that “already addressed the issue” (55361).

Processes Set for Permian Projects

The commissioners approved staff’s plans to streamline and expedite the selection of transmission companies responsible for building projects in the Permian Basin Reliability Plan (57152).

Staff recommended a bifurcated contested case system where projects without disputes between transmission service providers (TSPs) and ERCOT over the responsibility for building lines and facilities would be grouped together in one proceeding.

TSPs with disputes will be able to file petitions for authorization to file for permits. Multiple petitions for the same project will be merged into a single contested case proceeding “as soon as practicable.” If necessary, the state Office of Administrative Hearings will hold hearings on the dispute.

ERCOT has laid out suggested principles it would follow in determining ownership of the plan’s projects.

The PUC approved the plan in September. It includes 765-kV and 345-kV infrastructure to support the region’s current and future power needs and new and upgraded local projects, as well as eight new import paths that will bring more power to the petroleum-rich region. (See Texas PUC Approves Permian Reliability Plan.)

Posted on

Calif. Revises Clean Truck Rules to Ease Compliance

California regulators have approved changes to a zero-emission truck regulation to make compliance easier, keeping their end of a deal with truck manufacturers over the transition to ZEVs.

The California Air Resources Board (CARB) voted Oct. 24 to adopt amendments to the Advanced Clean Trucks (ACT) regulation. ACT requires medium- and heavy-duty truck manufacturers to provide zero-emission vehicles as an increasing percentage of their annual sales in the state. The regulation takes effect with model year 2024, but manufacturers have been able to earn early credits since model year 2021 with options to bank and trade credits.

If truck makers don’t meet their quota in a particular year, they’ll now have three years to make up the deficit, rather than the one year allowed before the amendment. Providing even more flexibility, credits from near-zero-emission trucks may now be used to meet up to half of the carried-over deficit. NZEVs, which include plug-in and wireless-charging hybrids, generate partial credits based on their all-electric range.

Another change to the ACT regulation is the manner in which ZEV credits are earned. Under the approved amendments, a manufacturer earns ZEV credits by producing and delivering a zero-emission truck for sale in California. Previously, the ZEV had to be sold to “the ultimate purchaser in California” in order to generate a credit.

“[Manufacturers] will no longer have to follow and document a vehicle’s entire pathway through upfitters and dealerships to its actual owner-operator,” Kat Talamantez of CARB’s mobile source control division said during the hearing.

Instead, manufacturers will receive credits when a ZEV is delivered to the initial entity, such as a dealer.

Clean Truck Partnership

CARB agreed to pursue changes to ACT as part of a deal it made with truck manufacturers in July 2023 called the Clean Truck Partnership. In exchange for CARB giving manufacturers more flexibility to comply with its regulations, the truck makers pledged to meet California’s vehicle standards, including a requirement to produce and sell only ZEVs starting with model year 2036. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)

And under the agreement, the manufacturers’ commitment will continue even if the regulations face legal challenges. The partnership includes CARB, the Truck and Engine Manufacturers Association, and 10 truck manufacturers.

In addition to ACT, the agreement addresses CARB’s heavy-duty engine and vehicle omnibus rule, a 2021 regulation that increased the stringency of tailpipe emission standards for trucks with internal combustion engines. The regulation allows the sale of a certain number of “legacy” engines that meet 2010 standards; in 2023, CARB raised the cap on legacy engine sales to help prevent a shortfall during a 2024-2026 transition period.

Diesel Engine Shortages

The proposed amendments to ACT were presented to the CARB board in May, but a vote was postponed after several dealers said they were having problems getting diesel trucks from California manufacturers. Some said the ACT regulation was to blame. The speculation is that manufacturers are withholding internal combustion trucks to reduce the number of ZEVs they’re required to provide.

CARB staff researched the issue, meeting with more than 40 dealers, fleet owners and manufacturer representatives.

The issue turned out to be “complicated with several contributing factors,” Talamantez told the board.

“However, all manufacturers have explicitly indicated that the product availability issues for the 2024 model year are not caused by the ACT regulation,” she said.

Further evidence that ACT is not causing diesel truck shortages is the ample supply of ZEV credits, CARB Executive Officer Steven Cliff said in a memo to the board.

CARB has noted that the number of ACT credits from model years 2021 and 2022 were about 60% more than the amount needed to meet requirements expected for model year 2024, and even more credits were racked up in model year 2023. (See California Far Outpacing Clean Truck Targets.)

Many truck manufacturers have accumulated their own ACT credits, and most are open to buying credits “if the economics make sense,” the memo said.

Instead, the diesel truck shortage may be related in part to the heavy-duty omnibus regulation and manufacturers’ “intentional business decision” to produce the limited number of engines that are not compliant with the regulation, as allowed by its legacy provisions, Talamantez said during the meeting.

Other factors contributing to the diesel truck shortage include a nationwide downturn in the market, lingering supply chain issues and manufacturers not yet being ready to comply with the omnibus regulation.

Cliff noted in his memo an apparent “discrepancy” between what manufacturers are telling their customers about the diesel truck shortage versus what they’re saying to CARB.

Cliff said truck makers might be telling customers the shortage is due to ACT as “a sales strategy to continue ramping up ZEV sales and towards building a credit bank for the ACT requirements in the 2025 and 2026 MYs despite the current surplus of ACT credits.”

Posted on

PJM, Monitor Seek Contract Resolution by End of Nov.

COLUMBUS, Ohio — The PJM Board of Managers and Monitoring Analytics are seeking a resolution by the end of next month to negotiations on the company’s contract to serve as Independent Market Monitor after more than a year.  

Speaking during the Organization of PJM States Inc. (OPSI) Annual Meeting on Oct. 22, PJM Manager David Mills said the contract review was initiated as a “corporate hygiene” effort to review longstanding agreements. The two parties have been meeting weekly with a mediator appointed through the FERC dispute resolution process — the sticking points of which Mills said are confidential. (See PJM Stakeholders Discuss Monitor Contract Review.) 

“There is no one in the room that wants this resolved more than I do,” Mills said. “It’s been a challenge; it’s a lot of work; but I want to go down why we started on this path: … [The board] has a series of fiduciary responsibilities. One of them is the duty of care, and so when this board took a look at all the existing contracts that the organization has in place, we had an eye to those that had not been reviewed and renegotiated.” 

Monitor Joe Bowring said the board did not have a proper succession plan in place to share information between outgoing and incoming members. While he expressed disappointment in the board’s review thus far, he said he is cautiously optimistic regarding [the] prospect of the mediation concluding in the coming weeks, stating that the efficacy of the process will be clear by late November. If common ground has not been found by that time, he said the Monitor will “move to whatever the next steps are.” 

“We’re disappointed in the board’s failure to engage in what we regard as productive and timely discussions at this point, but we’ve been trying to talk to the board about this for two or three years, and as the cliché goes, ‘actions speak louder than words,’” Bowring said. “So we don’t think the board fully understands or appreciates the role of a truly Independent Market Monitor.” 

Bowring said the continued negotiations and uncertainty around their outcome are impinging on the firm’s ability to fulfill its monitoring role, with staff wondering if their jobs are secure and considering taking positions elsewhere. 

“We’re already at the point where this is impinging on our planning; we’re already at the point where it’s affecting how we enter into contracts for hardware and software,” Bowring said. “So it’s already having a significant effect on the morale of my folks. … We’re not willing to let it go past the end of November without taking some additional action,” though he is “not sure what that would be.”

“This is the longest it’s ever taken,” Bowring continued. “It’s never gone this late into the process before, so we’re in uncharted waters. But it creates very significant uncertainty for us and makes our ongoing functioning more difficult; we’ve lost some people as a result of this; I suspect some people are starting to look around as it becomes more public what’s going on.” 

North Carolina Utilities Commission Senior Attorney Jennifer Harrod said the Monitor operates on a defined-term contract that is regularly reviewed by PJM and state commission staff. She said the ongoing negotiations have no clear benefit to consumers and create a distraction affecting the Monitor’s work. 

“Independence of the Market Monitor is paramount,” she said. “We can’t have an RTO without that independent market monitor, and I speak not out of any loyalty to Dr. Bowring in particular or Monitoring Analytics. … The functioning of the market requires that independence, and we are definitely extremely concerned that independence is under attack. And it’s not necessarily as a result of the intent of PJM or the PJM board … but at least to a certain extent, it’s the perception that that independence is under attack.” 

Mills responded that there is no endgame to replace the Monitor or impugn the independence of the role. The focus is on reviewing an agreement that has seen little change since it was implemented, he said. (See PJM, IMM Extend Contract Through 2025.)

“The contract is more than 20 years old. Yes, you’re correct the current version of the contract was inked, I believe, in 2018, but the contract and the service level agreements and rate schedules attached to it have lived on nearly virtually unchanged since they were conceived,” Mills said. 

Maryland Public Service Commissioner Michael T. Richard said his colleagues, as well as the Maryland Office of People’s Counsel, rely on the Monitor to understand the complexities of PJM’s markets. 

“Talking to commissioners in my state and some of our People’s Counsel and others, they all just emphasize how much we depend on the Market Monitor to have confidence in PJM,” Richard said. “And at this point with the complicated issues before us and the turmoil that is all around us in the PJM footprint, this is something that’s very distracting. We need to have a Market Monitor that can fully focus on these important issues. … I want you to be able to do your job with whatever this hygiene is you’re talking about, but again what’s really important is we get on with making sure we have a fully functioning Independent Market Monitor right now.” 

Posted on

PJM MRC/MC Preview: Oct. 30, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the upcoming PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance drafted through the document’s periodic review. The changes include clarifications to the transmission facility ratings process, grammatical corrections and removing the legacy NERC Functional Model.

C. Endorse proposed revisions to Manual 14F: Competitive Planning Process proposed as part of the manual’s periodic review. The revisions would make formatting and grammatical corrections, remove out-of-date references, update instructions for uploading files to PJM and reorganize some sections.

D. Endorse proposed revisions to Manual 21B: PJM Rules and Procedures for Determination of Generating Capability to update the definition of dual fuel gas generators to align with tariff language approved in ER24-1988. (See “Stakeholders Endorse Dual Fuel Manual Definitions,” PJM PC/TEAC Briefs: Oct. 8, 2024.)

E. Endorse proposed revisions to the tariff and Operating Agreement (OA) to eliminate the High/Low and Marginal Cost Proxy approaches to interface pricing. (See “PJM Proposes Elimination of Two Interface Pricing Models,” PJM MRC Briefs: Sept. 25, 2024.)

Issue Tracking: Interface Pricing for Non-market Entities 

Endorsements (9:10-10:30)

1. Credit Risk Arising from Bilateral Capacity Transactions (9:10-9:30) 

PJM’s Gwen Kelly will review a proposal to increase its review of the creditworthiness of parties to a bilateral capacity transaction. (See “First Read on Increased Review of Credit Risk for Bilateral Capacity Transactions,” PJM MRC Briefs: Sept. 25, 2024.) 

The committee will be asked to endorse the proposed solution and corresponding tariff revisions. 

Issue Tracking: Credit Risk Arising from Bilateral Capacity Transactions 

2. Capacity Market Enhancements — Data Transparency (9:30-9:50)

LS Power’s Tom Hoatson will review a problem statement and issue charge asking stakeholders to consider expanding the transparency of PJM’s effective load carrying capability (ELCC) approach to accreditation. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.) 

The committee will be asked to endorse the proposed issue charge. 

3. ELCC Capacity Accreditation Methodology (9:50-10:10) 

Hoatson will review a second problem statement and issue charge pair addressing the marginal ELCC design and how it is used to determine resource accreditation. 

The committee will be asked to endorse the proposed issue charge. 

4. Storage Integration (Phase II): Transmission Asset Utilization in Operations (10:10-10:30)

PJM’s Dave Anders will review a problem statement and issue charge exploring the implementation of storage as a transmission asset (SATA). During the Sept. 25 first read, Anders said discussion on SATA had been tabled by stakeholders four years ago. But PJM believes the subject should be reopened, as storage is increasingly viewed as a solution to costly reliability must-run agreements with deactivating resources. (See “PJM Proposes Reopening Discussion of Storage as a Transmission Asset,” PJM MRC Briefs: Sept. 25, 2024.) 

The committee will be asked to approve the issue charge. 

Members Committee

Consent Agenda (1:35-1:40)

B. Endorse proposed revisions to Manual 15: Cost Development Guidelines prepared through the document’s periodic review. The changes include correcting several formulas throughout the manual and removing the variable operations and maintenance (VOM) default values table to point instead to annually updated values on the PJM website. (See “Other Committee Activities,” PJM MIC Briefs: Sept. 11, 2024.)

Posted on

FERC Approves New MISO Probabilistic Capacity Accreditation

FERC on Oct. 25 authorized MISO’s move to a capacity accreditation method that blends probabilistic availability with historical unit performance beginning with the 2028/29 planning year (ER24-1638).

The commission said that MISO had shown its new method “captures a range of risks in the planning and operations horizons, aligns operational needs with non-discriminatory market and planning requirements, and will result in transparent market prices that reflect marginal contributions to reliability during highest-risk hours.”

The new method stands to shrink most resources’ accredited capacity. MISO will use a two-step process that marries historical performance of individual generators with a probabilistic performance during simulated loss-of-load events. (See MISO: New Capacity Accreditation Filing Imminent.)

First, the RTO will calculate a probabilistic, resource-class average accreditation using its loss-of-load modeling. Then, it will tailor resource class-level accreditations to individual generators based on their availability during normal operating conditions and at high-risk hours, which includes hours containing low margins or hours with an emergency event in place. MISO plans to give a greater, 80% weight to hours that contain emergency or near-emergency conditions in the ensuing method.

The RTO said it targeted both a prospective and retrospective approach to accreditation.

FERC rejected stakeholders’ arguments that MISO’s methodology differs from NYISO’s and PJM’s effective load-carrying capability method, noting that it has the authority to accept a range of designs. It called the RTO’s design a “reasonable balance of a range of complex tradeoffs that are inherent to any capacity accreditation methodology that includes probabilistic and deterministic elements.”

The commission said it found no evidence that the new method will introduce too much volatility in capacity values year over year, as the Arkansas and Mississippi public service commissions alleged. It countered that MISO is moderating volatility by using 30 years of weather data over its multiple simulations and including ordinary and low-margin operating hours in addition to loss-of-load hours to inform its accreditation.

FERC said MISO’s method recognizes “the diminishing marginal returns of surplus resources as the resource mix changes over time, which should send accurate price signals that will prevent oversaturation of one resource type, as well as encourage investment in diverse resource types.”

The commission also dismissed the Organization of MISO States’ argument that the RTO did not demonstrate how its weighting of emergency, near-emergency and ordinary hours is an improvement over strictly using loss-of-load hours. FERC said MISO is responsible only for proving its method is reasonable, not that it’s superior to alternatives.

FERC also said it wasn’t concerned with MISO using its loss-of-load expectation modeling as a centerpiece of the accreditation. While some stakeholders criticized MISO’s LOLE modeling as not sophisticated enough, the commission agreed with MISO that it has been a ballast of the RTO’s resource adequacy requirements for more than 15 years.

The commission likewise found nothing unfair in MISO’s LOLE modeling of storage, which assumes storage is deployed only after thermal and renewable resources can’t cover needs. MISO’s modeling “reasonably captures the value and limitations of storage resources,” it said.

MISO has told stakeholders it will focus on improving its LOLE modeling in a separate effort.

The commission overruled clean energy groups’ arguments that the new method would undervalue contributions from wind and solar resources. FERC said the design uniformly assigns capacity values among resources “based on their expected ability to meet the system’s resource adequacy needs” while accounting for “the differing performance of all resources within a resource class using the same metric.”

FERC said that if, for example, a high penetration of solar resources pushes risky hours later into the evening, it’s appropriate for their accreditation to reflect their declining marginal value.

The commission said there seemed to be sufficient data transparency worked into MISO’s resource class aggregation calculations. It said the RTO’s proposed use of aggregated, masked and class average data is consistent with how it handles generators’ data in other applications.

“We note that MISO has committed to working with stakeholders to further address data transparency issues to find a mutually acceptable process that maintains confidentiality while providing stakeholders with the information they need to replicate accreditation values,” FERC added.

FERC also accepted MISO’s proposal to include its 11 current resource classes in its tariff: gas and oil, combined cycle, coal, hydropower, nuclear, pumped storage, storage, solar, wind, run-of-river and biomass. It rejected arguments that the categories were too vague and said MISO grouped resources fittingly based on fuel type and similar operating characteristics. FERC also waved away arguments that the RTO should create resource classes for hybrid and co-located resources, ruling that tailoring classes to numerous combinations would result in too many that contain too few resources to return stable accreditation figures.

MISO has said it will create a process under its Business Practices Manuals to indicate when it and stakeholders should consider adding resource classes or adjusting them.

FERC refused to grant stakeholders’ requests to delay the method taking effect until 2030 at the earliest. The commission said a three-year transition period should give generation owners enough time to prepare while respecting MISO’s need to “act in a timely manner to address changes in its generation fleet that are impacting reliability.”

Finally, FERC addressed the Mississippi Public Service Commission’s concerns that MISO’s stakeholder process leading up to the proposal had become “form over function” and a “check-the-box exercise, where MISO makes a presentation and requests feedback; stakeholders provide feedback; MISO responds to the feedback it chooses with generalized summaries; but MISO ultimately files whatever it wants because stakeholder opinions are advisory only.”

The commission noted that MISO began working with stakeholders on the new method in early 2022. It said MISO appears willing to take under advisement ways it could further improve its probabilistic modeling and said staff appear ready to help generation owners understand how the change in methodology will affect their capacity values.

Posted on

Exploring Alternatives to Hyperscale at the USEA Energy Tech Forum

WASHINGTON ― Not every data center has to be hyperscale, according to Andrew Webber, founder and CEO of Digital Power Optimization. 

Finding the sites and hundreds of megawatts of power these massive facilities need is “rather limited,” Webber told the audience at the U.S. Energy Association’s Energy Tech Connect Forum on Oct. 24. Rather, DPO looks to co-locate its data centers with smaller stranded or underused power projects. 

“That’s kind of the point of our business,” he said. “We can flow like water in the cracks and around the energy sector and make use of assets that are otherwise undervalued. … Our view is size isn’t the only deciding factor, and in fact, the most efficient developments, the lowest-cost power may be in smaller sizes. It’s more distributed in smaller footprints all over the country … using existing infrastructure.” 

DPO started out in 2022, powering cryptocurrency mining facilities from a 6-MW hydropower facility in Wisconsin. This year, it entered into a partnership with Schneider Electric to develop modular artificial intelligence data centers that will draw on up to 100 MW of power from existing wind energy installations in Texas.  

Webber was one of three speakers on a panel looking at companies that have developed different, profitable models for meeting the challenges of powering the digital economy. Much of the dialogue in the power and tech industries has revolved around the tech giants ― Microsoft, Google and Amazon ― developing hyperscale facilities, said Tom Mapes, president of the nonprofit Digital Energy Council, who moderated the session. 

Exact estimates from different industry analysts vary, but the general consensus is that energy demand from U.S. data centers will grow two- to threefold by 2030, accounting for anywhere from 7.5% to 9% of total electricity consumption. (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand.)

“We’re using this kind of broad language to try to hit this generation demand issue, and it’s more nuanced than that,” Mapes said. “There are more pieces to this puzzle than just data centers, AI.” 

TeraWulf, which develops both bitcoin and AI data centers, looks for “dirty sites” to clean up, said Sean Farrell, the company’s senior vice president of operations. “We’re heavily looking at coal plants, pulp and paper, and steel plants across the U.S. and outside the U.S. A lot of those were built 30 to 40 years ago.” 

Located on the New York shore of Lake Ontario, TeraWulf’s Lake Mariner data center campus is built on the site of a former coal plant but is powered primarily with hydropower and nuclear. This month, the company announced a new long-term lease for the site that will allow it to expand its facilities from 500 MW to 750 MW.  

CleanSpark brings bitcoin mining facilities to small towns, where it can have major positive impacts on local economies, said Chief Operating Officer Scott Garrison. The company has 26 sites in Georgia, totaling around 700 MW, which can serve as grid assets for municipal utilities or electric cooperatives.  

CleanSpark owns all the servers in its facilities, so for “many of our utilities, I can shut the power off and give it back at any time,” Garrison said. “We’re building infrastructure for small, rural towns.” 

Keeping its facilities small also gives the company flexibility to take power off local electric systems for shorter periods of time, he said. For example, a utility might build a substation for a new data center, which will not be at full capacity for several years. “I can sit there for two to three years, create revenue for your town and your state, and then we can move on to other places,” he said. “There are plenty of areas that have stranded power.” 

Webber agreed, arguing that bitcoin mining should be viewed “as energy management infrastructure. … From the standpoint of the ability to turn it on and off, the ability to ramp it up and ramp it back down, it’s the perfect tool for energy companies to use for their own purposes and their own benefit, if only they understood it a little better. 

“There’s a way to make energy companies more profitable by deploying these [facilities] in a more thoughtful way.” 

Massive Capacity Waste

Farrell pointed to another benefit of TeraWulf’s model of putting data centers on the site of former coal plants with existing interconnection infrastructure: shorter times in interconnection queues. 

For a project in MISO’s service territory, TeraWulf has applied for MISO’s Net Zero Interconnection Service, which allows a generation project to use excess interconnection service at a point of interconnection, he said.  

But Farrell also cautioned that different kinds of data centers — for bitcoin mining, high performance computing and AI — have different power backup and interconnection needs. Grid modeling will have to incorporate different options for “how we can optimize those assets at those locations, because definitely one size does not fit all,” he said. 

High-performance computing, or HPC, differs from AI in that it uses clusters of computers to process large amounts of data at super high speeds, as opposed to the sophisticated algorithms that AI uses for higher computing functions, like data analysis.  

Webber said the way forward for data centers is “to try to find a pathway … without needing to change regulations or without needing to modify someone’s opinions or approvals or the regulatory overlay, because again, it’s [more] time.” 

Data centers’ search for clean, dispatchable power ― like advanced nuclear ― could drive major changes, but no easy answers in the electric power industry, he said. Regulators and other decisions makers need to familiarize themselves with the different generation technologies, different types of data centers and potential impacts of both on the grid. 

One example, Webber said, is that hyperscale data centers can be highly inefficient because although they run 24/7, they may not always use their full computing capacity 24/7. 

“That is just an absolutely massive amount of capacity waste, infrastructure waste [and] capital waste,” he said. “If you’ve got the connection and you’ve got the power availability, make sure you’re actually using it, and that will help prevent the need to build quite so much,” he said. 

The challenges surrounding data centers and their power demand power ― and their possible solutions ― are not likely to be affected by the coming election, Mapes said. “No matter who wins in a couple weeks, this conversation is only going to grow,” he said, and it needs to move out of what he sees as separate tech and energy industry silos.  

As data center efficiency improves, Mapes envisions “different data centers for different opportunities and regions.” 

“What we’re trying to do is … get some of these conversations up to the forefront, start talking about these now on the front end as opposed to trying to fly the plane and build it at the same time,” he said. 

Posted on

BPA Markets+ Support Intact Despite Exec’s Resignation, Agency Says

The Bonneville Power Administration’s commitment to fund the second phase of SPP’s Markets+ won’t be swayed by the departure of the executive leading the agency’s day-ahead market initiative, a BPA official told members of the Markets+ Participants Executive Committee (MPEC) in an Oct. 22 email obtained by RTO Insider.

The executive in question is BPA Director of Market Initiatives Russ Mantifel, who resigned effective Oct. 19, according to agency spokesperson Doug Johnson. Since July 2023, Mantifel has led the BPA’s intensive process to explore participation in a Western day-ahead market.

From day one, the effort spurred an increasingly contentious competition for participants between Markets+ and CAISO’s Extended Day-Ahead Market (EDAM), in large part because of BPA’s outsized importance in the Northwest electricity sector, where it controls more than 70% of the region’s transmission system and a massive amount of hydroelectric output.

Case in point: On the same day BPA kicked off its day-ahead markets process, a group of Western utility commissioners issued their letter establishing the West-Wide Governance Pathways Initiative to counter Markets+ by proposing a new organization to provide independent governance for CAISO’s EDAM and Western Energy Imbalance Market. (See Regulators Propose New Independent Western RTO.)

The competition between the respective camps supporting either market intensified in March when BPA staff released a report recommending that the agency choose Markets+ over EDAM. (See BPA Staff Recommends Markets+ over EDAM.)

That staff “leaning” was supported by most — but not all — of BPA’s customer base of publicly owned utilities and opposed by many environmental groups, Northwest utilities such as Portland General Electric, PacifiCorp and Seattle City Light, and all four Democratic U.S. senators representing Oregon and Washington. (See ‘Leaning’ Evident in BPA Response to NW Senators.)

In August, BPA said it would delay making its final decision on a market until May 2025. (See BPA Postpones Day-ahead Market Decision Until 2025.)

At the Oct. 22-24 fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB), multiple attendees told RTO Insider they were surprised by both the timing and abruptness of Mantifel’s departure, in part because the agency is scheduled to hold its next day-ahead participation workshop Nov. 4.

BPA’s Johnson said Mantifel’s resignation was effective Oct. 19, but the reason was for Mantifel alone — and not BPA — to disclose. Mantifel could not be reached for comment.

Johnson also said BPA is working to put someone in Mantifel’s position temporarily in early November and then will begin the process to fill the position long term.

In the meantime, he said, any interested parties should contact BPA’s acting Chief Information Officer Nita Zimmerman or Vice President of Power Bulk Marketing Rachel Dibble about market-related issues.

In the email obtained by RTO Insider, it was Dibble who told MPEC members that while Mantifel’s resignation “does leave a gap in our staffing at BPA, I want to assure you that this does not impact our commitment to Markets+ development. We intend to fund Phase 2 and continue our public process working toward our final decision in May.”

BPA’s share of funding for that phase is estimated at $25 million, representing a 17.4% share, second only to Powerex’s 23.2% share. (See BPA to Fund Phase 2 of Markets+, Agency Exec Says.)

The MPEC will meet Nov. 12-13 at the Oregon Convention Center in Portland, near BPA’s headquarters.