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November 27, 2024

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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.)

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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.”

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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.” 

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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.)

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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.

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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. 

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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.

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USDA Unlocks $3B+ for Rural Electrification Projects

The U.S. Department of Agriculture said Oct. 25 it will issue more than $3 billion to support clean electricity development at seven rural electric cooperatives from South Carolina to Colorado.

The announcement marks “the largest investment in rural electrification since President Franklin Delano Roosevelt signed the Rural Electrification Act into law in 1936,” according to a press release from the agency.

The funds are available through the USDA’s Empowering Rural America (ERA) program, which aims to create jobs and lower electricity costs in nine states. (See USDA Program Offers $7.3B to 16 Rural Cooperatives.)

“Since day one of his administration, President Biden has remained committed to ensuring rural communities are directly benefiting from a clean energy economy,” USDA Secretary Tom Vilsack said at a Westminster, Colo. press conference. “Through today’s announcement, USDA is delivering on this commitment with critical funding from the president’s historic Inflation Reduction Act. These projects will strengthen America’s energy security while increasing access to affordable and reliable clean energy for people across the nation.”

Nearly $2.5 billion is being allocated to Tri-State Generation and Transmission Association to accelerate clean energy projects. Tri-State, which provides wholesale electricity to 41 member cooperatives, plans to use the new ERA funds to purchase 1,040 MW of renewable energy and more than 200 MW of energy storage, as well as to refinance 1,100 MW of previously and newly announced coal-fired generation retirements.

USDA expects the investment to provide multiple benefits, including reducing electricity rates for cooperative customers by 10% by 2034, amassing $430 million in rural consumer benefits over 10 years, reducing carbon emissions by nearly 5.8 million tons annually and creating more than 2,000 jobs.

6 Cooperatives Selected for ERA Funds

Nearly $1 billion in ERA funds will flow to six cooperatives, which will leverage investments of $6.4 billion for 1.75 GW of clean energy for rural communities across the country.

The six co-ops all serve rural communities and include Connexus Energy, which operates in Minnesota and South Dakota, Central Electric Power Cooperative in South Carolina, Poudre Valley Rural Electric Association in Colorado, Nebraska Electric Generation, Rayburn Electric Cooperative in Texas and Yampa Valley Electric Association in Colorado.

The investment is expected to help reduce and avoid at least 6.4 million tons of greenhouse gases annually, USDA said.

Farmer Benefit Plan

The USDA also announced a new Farmer Benefit Plan, which serves as a roadmap for rural electric cooperatives and farmers to raise opportunities for clean energy and collaborate on a community benefit plan. Based on new ERA applications received so far, co-ops are collaborating with 154 local community groups, including 50 farm organizations, to explore local priorities.

Tri-State also is participating in that initiative and will develop a plan aiming to reduce electricity costs for farmers who take part in a smart irrigation program. The goal of the program is to lower pumping load at times of peak demand, which could help reduce future energy demand and offset the need to build new transmission and generation, saving co-op members from future costs.

Tri-State also plans to work with farmers to execute additional energy programs to encourage the most efficient use of electricity and water and will provide free technical support to enable participation.

Including the Oct. 25 announcements, the USDA has unlocked more than $8.3 billion in funding as part of the new ERA program, an investment the agency expects will result in more than $13 billion in financed grants and loans. The plan advances the Biden Administration’s Justice40 initiative, which requires 40% of benefits from federal climate, clean energy and affordable and sustainable housing initiatives to flow to disadvantaged communities. USDA estimates one in five Americans will benefit from the newly announced investments. (See USDA Announces $10.7B for Rural Clean Energy Projects.)

“All across America, rural electric cooperatives play an important role in delivering reliable sources of energy to rural communities. Under President Biden and Vice President Harris’ leadership, we are making significant investments to ensure that those communities are receiving clean, carbon-free energy — which will reduce the pollution in our air and water, create good-paying jobs, and lower families’ home energy costs,” White House National Climate Advisor Ali Zaidi said.

“By helping rural cooperatives upgrade infrastructure and invest in newer, lower cost clean electricity projects, these investments will benefit rural families and businesses who for too long have faced disproportionately high energy costs due to the challenges of providing electricity in remote communities,” he said.

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ACEG Report Checks in on Regional Planning After Order 1920

Most of the FERC-jurisdictional ISO/RTOs have made progress on transmission planning practices in response to Order 1920, Americans for a Clean Energy Grid said in an Oct. 24 report.

The report, “2024 State of Regional Transmission Planning: An Interim Transmission Planning and Development Report Card” was meant to follow an ACEG report in 2023 that graded grid operators’ rules. (See Transmission Report Card Grades MISO ‘B,’ Southeast ‘F’.)

“We find that across the country, several regions have initiated steps to reform their long-term regional transmission planning processes,” the report said. “Many of those reforms are promising improvements. However, despite the promise, many of these reforms are also in early stages of implementation and it is not clear what the final outcome will be or how it will impact actual transmission development.”

Compliance with Order 1920 is required by June 2025, though the report noted this could change as FERC acts on rehearing. FERC gave entities an extra 30 days after issuing a substantive rehearing order for Order 2023 on interconnection reforms. It is also uncertain whether all transmission planning regions around the country will comply with Order 1920 because of court challenges, though parties generally comply with orders even as they are being considered by courts.

“Two regions, the Southwest Power Pool (SPP) and the California Independent System Operator (CAISO), are pursuing reforms to more fully integrate or harmonize transmission planning and generation interconnection processes, which is encouraged but not required by Order No. 1920,” the report said.

SPP expects to send FERC its Consolidated Planning Process reforms in coordination with its Order 1920 compliance filing.

“The intent of the CPP is to fully integrate SPP’s interconnection and transmission planning process,” the report said. “The CPP has the potential to be a significant improvement, and the first of its kind in the country, but the process is still in its early stages, and it is not yet clear what the outcome will be.”

SPP has also improved its load and resource forecasting, including the incorporation of extreme weather scenarios.

CAISO received one of the highest grades in the original report, a B, with the new report noting it is the only organized market that has consistently done proactive long-term, scenario-based planning for a decade. The state’s energy and climate goals require major investments in the coming decades with CAISO’s latest 20-year transmission outlook calling for $45.8 billion to $63.2 billion in transmission investment to interconnect 165 GW of additional supply.

It has continued to build on that with its 2023-2024 Transmission Plan, which was the result of close coordination between the ISO and state agencies like the PUC and Energy Commission. It recommended 26 projects with a cost estimate of $6 billion.

“The plan builds on the previously established zonal approach, where specific resource zones and related transmission upgrades are identified,” the report said. “This coordinated process between CAISO, CPUC, and CEC and the resulting identification of resource zones helps better synchronize transmission planning, the interconnection process, and the CPUC’s Integrated Resource Planning process and resource procurement by Load Serving Entities.”

New York continues to make investments in transmission with more than $20 billion planned through NYISO and state initiatives. Shortly after the last report, the state’s utilities started the Coordinated Grid Planning Process (CGPP), a long-term, scenario-based process to better integrate their local planning processes with NYISO’s regional efforts.

“There is still work to be done to better integrate NYISO’s reliability, economic, and public policy planning as well as opportunities to optimize NYISO and the New York Public Service Commission (NYPSC) processes, and it is not yet clear how much of that can be accomplished through the CGPP,” the report said.

ISO-NE and PJM are both taking steps to develop and implement improved long-term regional transmission planning.

“ISO-NE is further along with its process,” the report said. “The region conducted a state-led, proactive, multi-value transmission study to evaluate transmission needs in 2050 required to meet state law and received tariff approval from FERC for its long-term transmission planning rules that enable the states to move forward with transmission investments in connection with the study.”

The states signaled their intent recently to focus new transmission development on unlocking generation in Maine and New Hampshire and to strengthen transfer capacity along the North-South interface. ISO-NE has also initiated the state engagement period that Order 1920 sets up to give state regulators a chance to come up with a cost allocation proposal.

PJM proposed reforms to its long-term regional transmission planning process, which would have included the development of three scenarios and more proactive generation forecasts, but those have been delayed as stakeholders decided the RTO should focus on complying with Order 1920. The reforms were a noted improvement in the new report for PJM, after it got a low grade in the initial version.

In the interim, PJM has seen needs for new transmission grow as load growth is driving new needs, with annual energy use now predicted to rise nearly 40% by 2039 and summer peak by 42 GW, or almost 30%.

MISO got one of the best grades in the previous report – a B – for its transmission planning process that was largely in line with Order 1920 already, but it has asked FERC for a one-year extension on compliance.

Still, the region has stayed the course with its long-range transmission planning (LRTP) initiative and other planning rules.

“For its second tranche, MISO has proposed a $21.8 billion portfolio of 1,800 miles of 765-kV backbone transmission lines and 1,800 miles of 345-kV lines to support the development of the backbone transmission lines,” ACEG said.

One lingering concern with MISO is its lack of a planning process in “MISO South,” which is largely Entergy’s territory, said the report.

ERCOT is the one domestic organized market FERC does not oversee, and in the 2023 report card it had low grades for transmission planning as it had not done much proactive planning in recent years.

“The region needs to improve its high-capacity transmission planning as it is facing some of the most significant load growth in the country and extreme weather will continue to stress a system that is islanded from its neighbors,” the report said. “This combination of load growth and extreme weather spurred legislation requiring reforms to transmission planning by the Public Utilities Commission of Texas (PUCT) and ERCOT.”

The processes are still in development, and it will take a few years to determine if they lead to major improvements in Texas transmission planning.

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ISO-NE Announces Pause of Order 1920 Compliance Discussions

ISO-NE is pausing its discussions with stakeholders on Order 1920 compliance due to uncertainty from outstanding rehearing requests, legal challenges and recent indications of potential updates to the order from FERC commissioners, the RTO told stakeholders at the NEPOOL Transmission Committee on Oct. 24.

The RTO said it has not decided whether to file for an extension of the order’s June 2025 compliance deadline, but said it remains “committed to a thoughtful and deliberate stakeholder process.”

“This decision was also made in response to significant demand for staff time in the area of system planning, particularly the implementation of the region’s new longer-term transmission planning (LTTP) process,” said ISO-NE spokesperson Matt Kakley. “Given the uncertainty surrounding Order No. 1920, we believe it is more prudent to have staff focus efforts on the implementation of LTTP while the rehearing and appeals processes play out.”

Both Order 1920 and ISO-NE’s LTTP, which FERC approved in July, are focused on promoting long-term transmission planning. While Order 1920 requires transmission operators to plan over a 20-year horizon and develop default cost-allocation methods, LTTP gives more deference to the states, allowing them to determine when to pursue a solicitation, which needs they should target and whether to proceed with a project selected by ISO-NE. (See FERC Approves New Pathway for New England Transmission Projects.)

The states recently announced their plans to focus the first LTTP solicitation on increasing New England’s north-south transmission capacity and unlocking renewables in northern Maine. (See New England States Seeking Increase of North-South Tx Capacity and “NESCOE Seeks Feedback on LTTP Solicitation Structure,” ISO-NE Planning Advisory Committee Briefs: Oct. 23, 2024.)

ISO-NE’s pause drew mixed reactions from stakeholders. While some encouraged the RTO to push ahead as much as possible with compliance, others agreed with the need to wait for more certainty on the order.

“This landmark rule requires considerable effort and coordination to comply, but its benefits — including cost savings and increased grid resilience — will outweigh any initial challenges. We strongly urge ISO-NE to follow the lead of other grid regions like PJM, capitalize on the progress already made and comply with Order 1920 to meet clean energy goals and maintain grid reliability,” said Claire Lang-Ree of the Natural Resources Defense Council.

Alex Lawton of Advanced Energy United expressed concern that the pause could lead to a compressed stakeholder engagement window but noted an extension would help to ease these concerns. He added that a silver lining to the pause appears to be the ability of the RTO to devote more resources to the LTTP process.

“Deferring compliance allows the ISO to focus exclusively on leveraging LTTP and executing a successful procurement, and also stretches the amount of time it can continue using LTTP unaltered, given the central role states play,” Lawton said.

Earlier in October, MISO announced plans to request a yearlong extension of its Order 1920 compliance, saying “much work and assessment is still needed to show compliance.” (See MISO to Request Year Deferral on FERC Order 1920.)

ISO-NE said it will keep stakeholders updated on its thought processes and will update the public when it plans to resume work on compliance.