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November 30, 2024

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Texas PUC Approves 1st System Resiliency Plan

Texas regulators on Nov. 14 approved the state’s first utility resiliency plan, a $3 billion proposal from Oncor to bulk up its distribution system over the next four years to better withstand and more quickly recover from extreme weather and other events (56545).

The Oncor System Resiliency Plan includes measures to mitigate wildfire risk, strengthen its overhead and underground distribution systems, protect against lightning strikes, expand vegetation management programs, implement physical security at critical facilities and strengthen the digital capability of its system against cybersecurity threats.

Oncor in August reached an unopposed settlement with Public Utility Commission staff, the Office of the Public Utility Counsel, the Alliance of Oncor Cities, the Steering Committee of Cities Served by Oncor, Texas Industrial Energy Consumers and Walmart over the plan.

Brian Lloyd, Oncor vice president of regulatory policy, said the utility worked with the intervenors to expand its vegetation management program in a “proactive, more efficient, cheaper manner” before storms hit, rather than cleaning up the damage and booking the costs after.

“We do believe this plan ultimately will mean we avoid costs,” he told the PUC commissioners during their open meeting. “The post-storm vegetation management is the most expensive vegetation management you can do, so by moving that ahead and doing it proactively, using our new technology to really tackle where that vegetation is grown the fastest, we do believe, over time, it’s going to have a significant impact.”

“Obviously, a lot of work went into this. Staff, all the intervenors, but definitely Oncor as well,” PUC Chair Thomas Gleeson said. “Going first is never easy. Thank you for working to get us a plan that we could ultimately support and that got broad-based support.”

“These investments have been methodically selected to have the greatest impact in proactively addressing potential outage causes,” Oncor CEO Allen Nye said in a statement. “And even more important to the people we serve, it will also substantially reduce outage minutes.”

Under House Bill 2555 passed by the 2023 Texas Legislature, electric utilities must file resiliency plans with the PUC. They must include measures that help prevent, withstand, mitigate or more promptly recover from resiliency events (e.g., extreme weather, wildfires and cybersecurity or physical security threats).

The commission also is reviewing plans filed by AEP Texas, Texas-New Mexico Power and Entergy Texas.

CenterPoint Audit

The PUC agreed to conduct a “management audit” of CenterPoint Energy over its post-storm recovery performance this year, meeting a request from Texas Lt. Gov. Dan Patrick, a Houston resident, during a rare public hearing in the city in October. (See Texas Politicos, Residents Bash CenterPoint.)

The commissioners directed staff to prepare a request for proposals for a third party to conduct the audit and deliver its findings in April. Gleeson said that will allow the commission to hand over findings and any recommendations to state lawmakers before they adjourn their biennial session in May.

“I think there are a few things we can look at, [like] CenterPoint’s policies and procedures when procuring goods from a third party,” Gleeson said, an apparent reference to the utility’s $800 million lease of portable generators that it was unable to use in restoring power following July’s Hurricane Beryl.

“I think it’s hard for us not to do something here,” Commissioner Jimmy Glotfelty said. “This is [Patrick’s] backyard, and he has been a part of this recovery from this hurricane since the very beginning. I think that we owe it to him to find some more answers, and this is an appropriate way to do so.”

The audit is separate from the PUC’s investigation into CenterPoint’s and other Houston-area utilities’ performance during Beryl and a May derecho that took out a major 345-kV transmission line. A report is due to Gov. Greg Abbott and the legislature by Dec. 1.

The commission also was prepared to rule on CenterPoint’s request to withdraw a $60 million rate case filed earlier this year, but the utility notified the PUC on Nov. 8 that it was withdrawing its request. CenterPoint said it instead would continue settlement negotiations with cities and consumer representatives that it had earlier claimed would distract it from its efforts to improve resilience and regain public confidence (56211).

The consumer groups have argued that CenterPoint overcharged customers by more than $100 million during the 2023 test case. The utility said withdrawing the rate case would have allowed it to use 2024 as its test year.

“We obviously heard from folks in Houston; we heard from the lieutenant governor and multiple members of the Senate on this,” Gleeson said. “I’m glad that they withdrew their appeal, and I look forward to this rate case.”

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Compromise Climate Bill Finally Approved by Mass. Legislature

After nearly two years of debates, negotiations, and last-minute stalling by Republicans in the state House of Representatives, the Massachusetts Legislature has sent a wide-ranging climate bill to the desk of Gov. Maura Healey, who has indicated she will sign the legislation.

The bill features major changes to the state’s permitting procedures for clean energy infrastructure and would make significant reforms to gas utility regulation, making it easier for the utilities to retire portions of the gas distribution network (S.2967). (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)

It also includes notable provisions supporting electric vehicle charging infrastructure, authorizing a major procurement of battery storage resources, increasing the allowable length of offshore wind contracts, and boosting advanced transmission technologies and advanced metering infrastructure.

The House and Senate failed to reach an agreement before the end of formal sessions in the summer to reconcile separate climate bills passed through each chamber, but legislators continued work into the fall and announced a compromise in October. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform.)

After the compromise bill passed the Senate by a vote of 38 to 2, Republicans in the House demanded a roll call vote, delaying its passage by three weeks. The House ultimately approved the bill with a vote of 128 to 17.

Climate and clean energy advocates in the state generally applauded the bill’s approval.

Kat Burnham of Advanced Energy United called the legislation “a crucial step forward,” adding that the permitting provisions “will eliminate the inefficient and duplicative processes that currently bog down clean energy projects.”

Jess Nahigian of the Sierra Club Massachusetts Chapter commended the legislature for the gas reforms, saying the “reasonable restrictions on expanding our polluting methane gas system … will protect ratepayers, reduce our reliance on fossil fuels and create healthier communities.”

Kyle Murray of the Acadia Center said the bill is a “major win for the Commonwealth, for ratepayers, public health, climate resiliency and for our clean energy future,” adding that the gas reforms “will provide the Department of Public Utilities with the needed tools to save ratepayers money on imprudent investments, stranded assets and leaky pipes.”

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Stakeholders Still Asking MISO for Smaller Tx Project Category to Address Congestion After MTEP 24 Study

CARMEL, Ind. — Stakeholders still are requesting that MISO develop a smaller, congestion-relieving transmission study after this year’s near-term congestion study focused solely on how best to sequence transmission outages needed for construction of recently approved long-range transmission projects.

Earlier this year, MISO pivoted its inaugural informational near-term congestion study under the 2024 Transmission Expansion Plan (MTEP 24) to evaluate the impacts of planned outages that will be necessary to build the first round of long-range transmission plan (LRTP) projects.

Stakeholders originally asked that MISO develop a process for smaller, congestion-relieving transmission projects like the Targeted Market Efficiency Project (TMEP) study it has with PJM. MISO, however, announced it would focus on the outages necessary for construction of the first, $10 billion LRTP.

MISO expects the bulk of outages to span from 2026 to 2028 and said it will be a complex task to schedule combinations of outages to minimize congestion costs. It estimates the system will experience about 220 outages related to LRTP construction, with half of those occurring in 2027. That’s in addition to the usual number of forced and planned transmission outages. MISO said it used random planned and forced outages to simulate system conditions.

At a Nov. 13 Planning Advisory Committee meeting, MISO confirmed that the outages will likely drive up adjusted production costs. In a worst-case scenario, construction delays and added curtailments could tack on $57.97 million to production costs.

Iowa’s ongoing court battle over who can build LRTP lines also could drag down the benefit, depending on how long the delay lasts. An Iowa district court last year froze permitting processes on Iowa’s portion of five of MISO’s LRTP projects after it found the state’s right-of-first-refusal law — which gave incumbent utilities first dibs on building MISO transmission projects — unconstitutional. That decision is pending appeal before the Iowa Supreme Court. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.)

MISO said it will issue recommended adjustments to outage arrangements and operating guide suggestions to transmission owners as a result of the study. The RTO also said it looked for stubborn congestion issues that persist no matter how outages are sequenced.

MISO engineer Bobby Klene said MISO now has an outage sequencing process that will be repeatable for construction in future LRTP portfolios. The RTO also is soliciting possible grid-enhancing technology solution ideas from stakeholders that could ease congestion during the outages.

Those stakeholders hoping for transmission upgrades resulting from MISO’s first near-term congestion study will have to wait. MISO said it will not recommend projects under this year’s study or under an upcoming one.

Stakeholders have said an outage sequencing project is not exactly what they had in mind when they asked for a near-term congestion study a few years ago. (See MISO May Use Inaugural Near-term Congestion Study to Plan Smaller Tx Upgrades.)

Klene said MISO will focus on building a near-term model over 2025 and embark on the next near-term congestion study in 2026. Again, that study will focus on construction outages, this time for the second, $21.8 billion LRTP portfolio.

Klene said MISO’s PROMOD modeling system simply isn’t built for conducting near-term congestion studies. However, he said PROMOD modeling can be adjusted to be more valuable for near-term congestion decisions.

Director of Expansion Planning Jeanna Furnish said stakeholders likely won’t hear much about congestion relief over 2025 while MISO planners complete an internal review of its model building and process to examine near-term congestion.

Clean Grid Alliance’s Rhonda Peters said some stakeholders still want MISO to take a shot at conducting a TMEP-style study within its own borders.

Peters said stakeholders were envisioning smaller, congestion-relieving projects that could be built within three to five years and cost less than $8 million.

“It would be important and valuable and useful to get back to the original intent of the study,” Peters said at an Oct. 30 Planning Subcommittee meeting.

“I’m not sure we’ve developed a meaningful process,” WPPI Energy’s Steve Leovy said, as he seconded Peters’ ask.

Leovy said he would like MISO to revisit the study’s focus with stakeholder discussions. He said the study’s structure as it stands today didn’t look like it could ever produce project recommendations.

Mississippi Public Service Commission consultant Bill Booth asked if future near-term congestion studies would always be tied to LRTP and never get the chance to stand on its own as TMEP-style study.

“Hopefully, at some point, LRTP will come to a screeching halt because it’s expensive,” Booth said.

MISO’s Victoria Jones said while this year’s study scope was limited to preventing congestion caused by LRTP construction, that’s not what the study always has to resemble.

“We can have discussions in the future about other types of near-term congestion studies,” Jones said.

The Planning Subcommittee ultimately voted down MISO’s proposal to remove creating a near-term congestion study from its active to-do list.

MISO’s Planning Advisory Committee overruled the Planning Subcommittee to give the issue inactive status; however, the committee added the caveat that MISO and stakeholders would revisit the issue around 2026.

Leovy said he would work with stakeholders to relaunch the possibility of small, congestion-relieving projects once MISO has a better handle on anticipating near-term congestion.

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PJM MRC/MC Preview: Nov. 21, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Nov. 21. 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)

D. Endorse proposed revisions to Manual 3: Transmission Operations drafted through the document’s periodic review. The changes aim to align the manual with existing practices on facility ratings, clarify the process for revising on-time transmission outages, and update several links and notes.

E. Endorse proposed revisions to Manual 10: Prescheduling Operations proposed through its periodic review. The language would clarify how inverter-based resources should report the amount of output that is offline during an outage into eDART and stipulate that forced outages must be completed before work can begin on planned outages.

F. Endorse proposed revisions to Manual 28: Operating Agreement Accounting to conform with a FERC order on lost opportunity costs (LOC) for intermittent resources (ER23-2484). The existing LOC credit calculation for wind generators would be extended to solar, hybrid and storage resources as well. (See “Stakeholders Endorse Expansion of Lost Opportunity Cost Credits for Renewables,” PJM MIC Briefs: Nov. 8, 2024.)

G. Approve a proposal to sunset the Clean Attribute Procurement Senior Task Force (CAPSTF). PJM proposed sunsetting the group, stating that it has completed its work and discussions of creating a market to trade clean energy attributes has shifted to discussions between states. (See “PJM Revives Proposal to Sunset Clean Attribute Procurement STF,” PJM MRC Briefs: Oct. 30, 2024.)

H. Endorse revisions to the tariff, Reliability Assurance Agreement (RAA), and Operating Agreement (OA) proposed by the Governing Document Enhancement & Clarification Subcommittee (GDECS) in October. The changes include removing sunset and obsolete terms and references, correcting drafting errors and clarifying instructions.

Endorsements (9:10-10:15)

1. Hybrids Phase 3 (9:10-9:30) 

PJM’s Maria Belenky will present the third phase of PJM’s rules for hybrid resources, which focuses on non-inverter generators paired with storage. Participation in the energy and ancillary service markets for such hybrids would be akin to the RTO’s Energy Storage Resource Participation Model, while capacity accreditation would center on the battery. The package also includes several clarifications and revisions to the rules for all hybrid resource classifications, such as how the storage component can shift between open- and closed-loop status. (See “Third Phase of Market Rules for Hybrid Resources Endorsed,” PJM MIC Briefs: Oct. 9, 2024.) 

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

Issue Tracking: Hybrid Resources Enhancements (Hybrids Phase 3) 

2. Enhancing Capacity Interconnection Rights (CIR) Transfer Efficiency (9:30-10:15)

A. PJM’s Ed Franks will review the main motion to establish an expedited process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource. The proposal would establish a nine-month parallel process that studies the grid impacts of the new resource based on the latest Phase 2 or 3 models being used to evaluate projects in the overall interconnection queue. Replacement resources with minor network upgrades would be permitted to proceed, but those with extensive cost allocations would be placed into the general queue. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)

B. Consumer Advocates of the PJM States (CAPS) Executive Director Greg Poulos is set to move an alternative proposal on behalf of the Delaware Division of the Public Advocate, which would ask the MRC to consider a design from the Independent Market Monitor where PJM would administer a competitive process for awarding CIRs to projects that would mitigate any transmission violations associated with a resource deactivation.

The committee will be asked to endorse one of the proposed solutions and corresponding tariff revisions. 

Issue Tracking: Enhancing Capacity Interconnection Rights (CIR) Transfer Efficiency 

Members Committee

Consent Agenda (11:05-11:10)

B. Endorse proposed tariff and OA revisions to eliminate the High/Low and Marginal Cost Proxy interface pricing options due to disuse. PJM stated that the last time the marginal-cost proxy was used was in July 2019, when Duke Energy Process terminated its dynamic interface. Nodal aggregate pricing now is used for interface pricing, with the belief that it creates more accurate price signals. (See “PJM Proposes Elimination of Two Interface Pricing Models,” PJM MRC Briefs: Sept. 25, 2024.)

Issue Tracking: Interface Pricing for Non-Market Entities 

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BPA: Funding Markets+ Phase 2 Preserves Choice

PORTLAND, Ore. — As potential participants in SPP’s Markets+ day-ahead offering gear up for the second phase of the day-ahead market offering, Bonneville Power Administration has emerged as the proverbial 800-pound gorilla.

With its 15,000 miles of transmission lines — about 70% of the region’s facilities — and 22 GW of low-cost hydroelectric power that it sells to its customer base of publicly owned utilities, BPA is seen by some as obstinately pursuing Markets+ membership rather than joining others in CAISO’s competing Extended Day-ahead Market (EDAM).

But BPA says that is not the case.

The federal agency says following through on its $25 million funding commitment to Markets+’ development, despite several studies that claim EDAM offers more benefits, is simply a matter of preserving a choice between the two markets. That and listening to the wishes of its “preference” customers, the utility districts, municipalities and cooperatives that buy BPA’s power.

“Our preference customers have been very clear. They want us to continue funding because what we have always said is, at the end of this process, we want to have two markets, two options to decide on,” BPA’s Rachel Dibble, vice president of wholesale markets, told RTO Insider Nov. 12. “Bonneville’s portion of [Phase 2 funding] is what we need to pay to keep that as a viable option.”

Dibble said BPA still is negotiating a funding agreement with SPP. She said there have not yet been any commitments, but the agency’s intent is to “get an agreement that works for us and to fund.”

SPP has set a Dec. 16 deadline to finalize funding arrangements.

“It has to be an agreement that everyone is comfortable with,” Dibble said. “SPP has always been very good to work with and flexible, because they just want everyone to have a say and to be able to get their concerns addressed.”

The majority of preference customers recently made clear where they stand with a letter to the U.S. Department of Energy, under which BPA is one of four regional federal power marketing administrations. The signatories said the letter was designed to remind the DOE and the region’s congressional delegation to respect BPA’s independent decision-making as it considers market options.

“Enabling BPA to act without external pressures will ensure its continued alignment with its statutory responsibilities and enduring mission to serve the Northwest,” the utilities said in the letter. (See Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process.)

“We’ve had very strong support from our preference customers. They really prefer Markets+,” Dibble said. “The governance is by far the most common reason that we hear from them, that they really want to make sure that we’re in a market where [BPA’s] discretion is protected and it’s an independent governance model. We just have to be careful about not letting that erode or violate our statutes.”

BPA has long pointed to SPP’s independent governance model — which includes building consensus among stakeholders before making decisions — as the primary reason for choosing Markets+ over EDAM. It has stuck with staff’s recommendation to make a qualitative decision and go with a governance framework independent from California state influence instead of basing it on various western market studies.

One such recent study by Energy and Environmental Economics (E3) found BPA would realize significantly greater economic benefits in EDAM than in Markets+. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.)

“Having the independent governance is something that’s a protection for us,” Dibble said. “What we’re just really trying to do is honor what our obligation is, and that’s to have a transparent, thorough, thoughtful, deeply analytical process … it’s the right thing to do.”

Among preference customers, Seattle City Light has stood out as an opponent of BPA’s leaning in favor of Markets+. In a Nov. 14 letter to BPA Administrator John Hairston, City Light CEO Dawn Lindell contended that BPA’s “disregard” for the E3 study results was “alarming” and criticized the agency for continuing to fund Markets+ while not contributing financially to the West-Wide Governance Pathways Initiative’s effort to bring more independent governance to CAISO’s markets.  (See related story, Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.)

BPA plans to issue a draft decision in early March and open it up for public comments. A final decision will be made in May.

Rachel Dibble, BPA | © RTO Insider LLC 

Dibble was just one of a half-dozen or so BPA staffers who attended the Nov. 12 Markets+ Participant Executive Committee about a mile from the agency’s headquarters building in Portland. She cast nearly 20 votes as the group easily approved the latest batch of protocol language, leaving only a few remaining sections that likely will be up for approval during MPEC’s January meeting in Tempe, Ariz.

Most of the language was brought forward by the Markets+ Design Working Group, which sought approval on everything from energy and flexibility products to “those things that go kerplunk,” according to the group’s vice chair, Xcel Energy’s Nick Detmer.

Detmer, who stepped in following the sudden recent departure of BPA’s Russ Mantifel, promised MPEC members the MDWG was “coming here with 240 minutes worth of exciting stuff, a lot of math, a lot of settlements, how we can handle things, how departments can interact, how we generate.” (See BPA Markets+ Support Intact Despite Exec’s Resignation, Agency Says.)

“Is [kerplunk] a defined term?” asked the Western Power Trading Forum’s Scott Miller, drawing laughter. Detmer explained that “kerplunk” refers to occasions where the market’s functions fail to solve.

“There’s instances where it’s delayed and that does happen occasionally, but in terms of kerplunk, that’s not a problem,” SPP’s Carrie Dixon said.

The MPEC tabled a discussion on a meeting-attendance policy until it gathers again in Arizona. It also delayed until August 2025 consideration of engaging an external adviser, offering insight on market design separate from SPP’s Market Monitoring Unit, over the scope of its work and compensation.

After Phase 1 market participants voiced conceptual support for an external adviser last year, a Markets+ legal subgroup suggested bringing on the advisory-only role in the second quarter of 2026. The contract would encompass the market’s targeted go-live date of May 2027 and would be paid by either load under the tariff or directly funded by MPEC participants.

However, compensation that could reach $2.5 million proved a sticking point as MPEC debated whether to pay the adviser by the issue studied or on a retainer.

“That seems like a lot to pay for an expert without having issues to look at. It seems to lack some prudence,” said MPEC Chair Laura Trolese, with The Energy Authority.

“It’s hard for me to have perspective on this,” the Public Generating Pool’s Mary Wiencke said. “Paying $2.5 million to do nothing? Yeah, I’d like to have that job.”

SPP’s Carrie Simpson said staff would take the committee’s input and provide more information by August, including a refinement of costs.

In other actions, MPEC members approved Tacoma Power’s Thad Levar and BPA’s Sara Eaton to fill public power vacancies on the MDWG and Michiko Sell, with Grant County (Wash.) PUD, to an open public power seat on the Markets+ Transmission Working Group.

As the meeting ended, Dibble appeared to be even more comfortable with SPP’s approach to Markets+.

“This is the first time we’ve been in the full SPP process,” Dibble said after the meeting ended. “I think all of us throughout the West are kind of learning it and trying to figure out how the meetings go. It’s something that definitely takes a lot of investment and you take responsibility for what’s actually being written. And that’s one of the features of independent governance that we know that we just need to invest a lot more time in.”

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MISO: Flag, Penalties Needed to Address Generators’ Uninstructed Deviation

CARMEL, Ind. — MISO said it expects to roll out a new flag system by June 2025 to give a stronger indication when generation owners are deviating from dispatch instructions.

MISO said there’s an “increasing difference in magnitude” between modeled flows in its dispatch system and actual flows, resulting in system operating limit violations, balancing issues and frequency deviations. The RTO said unchecked energy flows are causing operators increasingly to take out-of-market actions, causing MISO to stray from its market design principles.

During a Nov. 14 Reliability Subcommittee meeting, John Harmon said uninstructed deviation creates a stressful environment for MISO’s operators “to keep the grid alive.”

The flag will let operators know more clearly when their resources are disregarding MISO’s dispatch instructions. The new system will require software changes to the unit dispatch system. In addition to the flag, the RTO also plans eventually to levy penalties in market settlements for generation that ignores dispatch instructions. Harmon said MISO will introduce penalties only when it has the flag system in place.

MISO has said instances of uninstructed deviation now are worse than before the RTO introduced rules in 2019 to rein them in.

Harmon said the point of the effort is to “improve communication” when MISO issues dispatch down instructions to intermittent resources, namely wind and solar.

He said some resources tend to ignore MISO’s setpoint instructions, leading to challenges for reliability coordinators and balancing authorities and operator action to avoid transmission overloads.

“We’re counting on resources to follow instructions to manage reliability,” Harmon said. He joked that operators must monitor their blood pressure in addition to transmission constraints.

While delivering an operations report during a July 9 Market Subcommittee, Independent Market Monitor David Patton again zeroed in on his concern over congestion caused by wind resources. He said wind operators seemingly either continue to ignore dispatch instructions or are unaware that they should tamp down output to avoid exacerbating constraints. He also said the RTO should improve the accuracy of its wind forecasting. (See “IMM Says MISO Should Rein in Renewable Operators,” MISO: Calm Spring no Indication of Expected Summer Challenges.)

IMM’s Carrie Milton told executives at MISO’s June Board Week that the dispatch model is flawed because it always assumes wind operators are following setpoint instructions. She said wind units either ignore curtailment instructions or receive flawed wind forecasts from the RTO, leading to excessive, unmodeled flows.

At the time, Milton repeated the IMM’s recommendation that MISO develop a flag to let wind operators unmistakably know that there are nearby constraints and that they need to back down as MISO has instructed. She said MISO also should introduce penalties when renewable operators ignore instructions to curtail.

“We need to have some sort of financial incentive to nudge renewables to follow their setpoint,” Milton said. She said the system is going to become more challenging and dynamic, and resources need to help MISO operators reduce manual actions to keep the system reliable.

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AEP Adding Fuel Cells as Temporary Data Center Power

American Electric Power will meet data center power demand with what it calls the largest utility initiative of its kind in the nation, buying up to 1 GW of Bloom Energy’s solid oxide fuel cells. 

AEP and Bloom announced the agreement Nov. 14. They said the fuel cell units typically will be used to allow data centers or other large energy users to quickly power up new or expanded operations while the grid is built up to meet their demand. 

Also Nov. 14, AEP subsidiary Appalachian Power announced it will explore a different technology: It plans to build small modular reactors in Virginia. It will start the early site application process for an installation near one of its substations in the south-central area of the state.  

Fuel Cells

AEP said it previously used Bloom’s technology to power customers and is in talks for new customer agreements. All costs would be borne by the large customers who would use the electricity.  

Bloom said the full 1 GW agreement would be the largest commercial procurement of fuel cells worldwide to date. It said AEP has placed an initial order for 100 MW of fuel cells, and said further orders are expected in 2025. 

The two companies said these fuel cells initially will operate on natural gas but could use hydrogen as an alternative fuel, or any blend of natural gas and hydrogen. 

They said carbon dioxide emissions would be 34% lower than present-day displaced marginal generation resources in the PJM interconnection. 

The fuel cells will be placed on-site where AEP’s customers operate and will be designed to not send any power to the grid. They will be required to meet local interconnection rules, and AEP will work with regulators to secure needed approvals. 

AEP is in the final stages of negotiating the first customer project agreements. It expects its commercial load to grow an average of 20% annually over the next three years, driven by data center development. 

“The rapid increase in energy demand is a challenge that AEP is tackling by finding innovative solutions to meet the unique needs of our customers,” AEP CEO Bill Fehrman said in a news release. “These fuel cells will help provide data centers and other large customers with the power they need to quickly expand in our regulated footprint as we continue to build infrastructure to deliver reliable energy for all our customers.” 

Bloom CEO KR Sridhar said the company has more than 1.3 GW of its products deployed and has multi-gigawatt annual production capacity for its Energy Server, a modular plug-and-play box that can serve as baseload power. 

“I am delighted that there is strong market recognition that the Bloom Energy platform is the ideal choice for powering AI data centers,” he said in a news release. “We are thrilled to be working with AEP as they lead the charge to bring innovative solutions to the transforming electricity market.” 

Bloom Energy stock exploded after the announcement, closing 59.2% higher in extremely heavy trading Nov. 15. 

Advanced Nuclear

Appalachian Power’s announcement that it wants to build small modular reactors (SMRs) in Virginia also was keyed to future electricity demand. 

Given that SMR designs still must be perfected, gain approvals, secure a fuel supply and be scaled to the point of commercial viability, the time frame is likely to be a bit longer than that envisioned in the AEP-Bloom agreement. 

Appalachian did not say what type of demand it expects to drive the need for the SMRs it wants to build. 

However, it has identified a potential site outside of Lynchburg on company property surrounding a 765-kV substation. 

This would be almost next door to BWX Technologies, a major supplier of nuclear components and fuel that is the lead contractor designing a portable microreactor for the U.S. Department of Defense through Project Pele. 

AEP CEO Fehrman and Appalachian President Aaron Walker spoke of the utility’s SMR initiative as a cooperative effort with states and thanked Virginia Gov. Glenn Youngkin (R) for embracing SMRs. 

Appalachian’s news release quoted Youngkin: “Advanced nuclear power is at the heart of Virginia’s All-American, All-of-the-Above Energy Plan, a plan that prioritizes abundant, reliable, affordable and increasingly clean power to fuel our thriving and growing economy.” 

Appalachian said it would file an application with the Virginia State Corporation Commission in the spring of 2025; would seek funding under the U.S. Department of Energy’s $900 million grant program to accelerate development and reduce cost of SMRs; and would work with regulators and stakeholders to educate the community and gather feedback. 

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Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA

The Bonneville Power Administration’s insistence on favoring joining SPP’s Markets+ over CAISO’s Extended Day-ahead Market (EDAM) is “alarming” and could lead to $221 million in economic advantages going up in smoke, Seattle City Light argued in a Nov. 14 letter addressed to BPA Administrator John Hairston.

Dawn Lindell, CEO of City Light, argued in the letter that BPA is ignoring a study by Energy and Environmental Economics (E3) — commissioned by the agency itself — showing that BPA would gain between $69 million and $221 million per year in economic advantages if it joined CAISO’s EDAM over Markets+.

Instead, BPA continues to argue that joining Markets+ would provide a much more favorable governance structure, despite ongoing efforts to alleviate those concerns in CAISO’s EDAM, Lindell wrote.

“At a time when City Light and other utilities throughout the region are working to contain costs for our customers, and against the backdrop of proposed double-digit rate increases for both BPA Power and Transmission customers, BPA’s disregard for the economic benefits to customers is alarming,” Lindell stated in the letter, on which Washington’s congressional delegation and U.S. Energy Department Deputy Secretary David Turk are copied.

The municipally owned utility is one of BPA’s largest “preference” customers and has been outspoken in its disagreement with the agency’s “leaning” toward Markets+. The majority of BPA’s customer base of publicly owned utilities have urged the agency to join the SPP market, something agency officials have said will factor heavily into its decision. (See related story, BPA: Funding Markets+ Phase 2 Preserves Choice.)

Representatives for BPA did not immediately return a request for comment.

The letter comes shortly after BPA’s Nov. 4 day-ahead market participation workshop, in which participants discussed E3’s findings. E3 estimated the comparative benefits of joining either Markets+ or CAISO’s EDAM under various market footprint scenarios and tested under different sensitivities, such as conditions of low hydro or stressed load. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.)

The study, which supplements the Western Markets Exploratory Group (WMEG) study that E3 produced for BPA in 2023, found the agency would gain significantly more financial benefits from participating in EDAM rather than Markets+, with the largest projected take in a single, West-wide market: $251 million in savings in 2026 — compared with a “Business as Usual” (BAU) case — declining to $147 million in 2035.

But in an Oct. 31 press release announcing the study results, BPA made clear the findings would not shift its leaning in favor of the SPP market, although they would still factor into its final decision. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)

Instead, BPA officials have pointed to other qualitative factors not captured in the E3 study, such as the benefit of participating in a market with independent governance from the get-go.

Other factors BPA has cited are more quantitative but still difficult to estimate in a study, such as the absence of scarcity pricing in the EDAM, market power mitigation practices, the impact of energy bid caps and the potential for CAISO — as both market operator and balancing authority participating in its own market — to “bias” operations in its own favor during stress events.

However, Lindell made clear in the letter that City Light remains unpersuaded, claiming that BPA has refused to meaningfully consider both options. For example, BPA has yet to provide any funding to the West-Wide Governance Pathways Initiative, launched to address governance concerns around the EDAM, while committing $25 million to fund Phase 2 of Markets+, Lindell noted.

“If BPA were conducting a fair analysis of market options, we would expect to see them engaging in and funding solutions to each market equally,” Lindell wrote. “Instead, we have seen BPA continue to favor Markets+ and provide significant staff time and funding to this market, while identifying concerns with EDAM but not engaging in efforts to resolve those concerns despite the consistently better economics related to EDAM.”

Additionally, the Markets+ footprint is limited and fragmented due to utilities’ preference for EDAM or the Western Energy Imbalance Market (WEIM), which could “unnecessarily increase costs and risks for BPA and its customers,” Lindell argued. She added that the fragmented market footprint poses reliability issues, especially with large loads looming on the horizon.

The E3 study also revealed that remaining in WEIM and joining no DAM “produced higher benefits for its customers than joining Markets+,” according to the letter.

“We believe markets are a way to mitigate upward rate pressure and to promote efficient usage of the region’s transmission system,” Lindell stated. “However, joining no DAM appears to be more prudent than joining the wrong market.”

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CAISO Launches Initiative to Examine CRR Issues

CAISO has launched an initiative to improve its congestion revenue rights market by addressing issues such as revenue inadequacy and auction efficiency. 

The ISO held a working group meeting Nov. 14 to kick off the stakeholder process for the initiative. It also released a discussion paper outlining the issues regarding CRRs.  

CRRs are intended to provide a hedging mechanism for congestion risks in the day-ahead market. They’re distributed through free allocations to load-serving entities and also are awarded through auctions in which a variety of entities may participate.

But auction efficiency has been a concern. According to CAISO, the CRR auction has been yielding only about 65 cents per dollar of congestion revenue. 

Revenue adequacy is another issue: From 2019-2024, system-level revenue inadequacy was 81%, with a total shortfall of $684 million. 

The current effort follows a previous initiative regarding CRR auction efficiency that led to rule changes in 2019. 

Since then, losses from CRR auctions have decreased, but have been described as “still very high” by the Department of Market Monitoring (DMM), a longtime auction critic. (See Congestion Revenue Rents Still Underfunded, CAISO DMM Says.) 

“The ISO should stop offering CRR positions on behalf of transmission ratepayers at $0 offer prices and enable trades to only take place between willing sellers bidding into a market for these financial contracts,” the DMM said in a presentation during the workshop, echoing an argument it has been making for years. (See CAISO CRRs Still Losing Money, but Less.) 

Working Group Timeline

The working group will develop problem statements that will lead to proposed policy solutions. Those proposals will go to the ISO Board of Governors and the Western Energy Markets Governing Body for approval and ultimately be filed with FERC. 

For the next steps in the process, CAISO staff have proposed following up the Nov. 14 meeting with one or two workshops in January to provide background information on the CRR market. The sessions would be geared toward those who recently have joined the stakeholder process and others who may need a refresher. 

At the same time, CAISO wants to learn more about how different entities are hedging risk through CRRs. 

Under the proposed timeline, February would be devoted to analysis, including CRR outcomes since the 2019 reforms. CAISO staff also have offered to provide benchmarking comparisons to CRR-like programs at other ISOs, which go by different names, such as financial transmission rights. 

March would feature discussions of proposed problem statements and the scope of the initiative, followed by release of an issue paper from the working group in May or June. 

CAISO welcomes comments on the CRR discussion paper and on the initial meeting — including the proposed focus of future meetings. Comments are due by the end of the day Dec. 12. 

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Pathways Initiative Issues Final ‘Step 2’ Proposal

The West-Wide Governance Pathways Initiative on Nov. 15 released its final proposal for establishing a Western “regional organization” (RO) that would assume oversight for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The proposal offers a blueprint for divvying up functions between CAISO and the RO that Pathways backers envision would provide an independent framework for governing the ISO’s Western markets. Launched in July 2023, the effort aims to address regional concerns about the state of California’s oversight of CAISO and to counter the appeal — and potential growth — of SPP’s Markets+, a competitor of EDAM for market participants.

The Pathways Launch Committee will vote on the proposal during its next public meeting Nov. 22. The content of the Step 2 proposal will play a big role in shaping the bill that Pathways supporters are looking to move through the California State Legislature in 2025 to relax the state’s authority over CAISO’s markets.

“This proposal marks a major milestone in a decades-long series of incremental steps,” Launch Committee Co-Chair Kathleen Staks, executive director of Western Freedom, said in a statement. “The regional organization will have sole authority over the energy markets, ensuring shared and independent Western ownership, while deliberately setting the stage for an organization empowered to develop its own regional solutions for years to come.”

The final plan adopts most of the recommendations the committee set out in its Step 2 draft proposal released in September, while incorporating stakeholder feedback on the draft. (See Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’.)

As in the draft, a key element of the final proposal is the Launch Committee’s choice to launch the RO in the form of the “Option 2.0” structure discussed during Pathways meetings. Under that option, the RO would serve primarily as a “policy-setting” body and assume “sole” authority over WEIM and EDAM market rules, holding exclusive rights to file with FERC under Section 205 of the Federal Power Act.

That stops short of the more comprehensive “Option 2.5,” which would see the RO take on more of CAISO’s market functions and legal responsibilities along with the accompanying financial and legal risks. But the plan states that, within nine months of the RO’s formation, the RO board must perform analysis of advancing toward Option 2.5.

“The feasibility analysis would at a minimum evaluate: vendor management role, financial liability, existing regulatory contract changes and future RO staffing needs,” the proposal notes.

The plan also calls for the RO to maintain a single, integrated tariff with the ISO instead of establishing a separate tariff. The Launch Committee recommends the Formation Committee work with CAISO “to explore ways to provide more clarity in the tariff that can be proposed to the RO board once it is seated.”

The proposal also describes how the RO would be funded: through “a tariff-based mechanism under which the CAISO collects funding from market participants and remits the funding to the RO.” It notes that the RO and CAISO would follow a stakeholder process to develop the mechanism and how it might “interrelate” with the ISO’s current approach to collecting its grid management charge. The mechanism would be subject to FERC approval.

Budget, Location, Relationship with CAISO

The plan says the RO would start out with “limited staffing” at an estimated budget of $1.25 million to $1.5 million, which eventually could increase to $10 million to $14 million over time.

The proposal also sets out how the RO would influence CAISO’s management and market monitoring structure, saying it would have “advisory authority to provide noncontrolling input on hiring and performance of one or more officer-level senior CAISO managers responsible for the business line (or ‘vertical’) that oversees the markets.”

It notes that CAISO’s Board of Governors would consider “the most appropriate way” for the RO board to advise on the hiring of any future CEO of the ISO. The two boards also would jointly select future heads of the ISO’s Department of Market Monitoring (DMM) and members of its Market Surveillance Committee.

The plan calls for the RO’s contract with CAISO to “provide an opportunity for the RO to offer an annual performance evaluation of the CAISO management personnel subject to the RO’s noncontrolling hiring input, including the CAISO officer(s) overseeing market services and the DMM.”

The proposal affirms the Launch Committee’s previous recommendation that the RO be incorporated as a 501(c)(3) nonprofit in Delaware and have its principal place of business in Folsom, Calif. — near CAISO’s headquarters.

It sets out the RO’s governance structure, including the seven-member board, the Formation Committee and the Public Policy Committee, the last of which would be “tasked with conducting outreach at key points in the stakeholder process to states, local power authorities and federal power marketing administrations to collect input about the potential for adverse impacts on a state, local or federal policy by an initiative.”

The Step 2 proposal also sketches out the RO’s framework for protecting the public interest, including the intention to carry over the existing Western Energy Markets Body of State Regulators (BOSR) into the RO and create an independent Consumer Advocate Organization and Office of Public Participation to facilitate engagement with the public.

The proposal’s program for stakeholder engagement includes the structure for the proposed Stakeholder Representative Committee (SRC) the Launch Committee discussed with stakeholders in October. (See Revised Pathways Proposal Focuses on Sector Issues.) The proposal notes that voting within the SRC is “ultimately advisory” and intended to identify “significant opposition” to an initiative; it says the Formation Committee in the future would work with a Stakeholder Process Work Group and stakeholders to develop the “remand” process to respond to such opposition.

The proposal additionally breaks out the roles for the SRC and RO staff in the stakeholder process. It also notes that the RO’s Formation Committee would work with CAISO to determine staffing for the RO’s stakeholder process and “to refine the roles needed” and identify whether they would “best sit with” the RO or CAISO.

‘Logical Next Step’

Most parties who commented on the draft proposal expressed support for the Launch Committee’s decision to proceed with Option 2.0 rather than a more aggressive option in which the RO would take on more responsibility for CAISO’s markets.

But key among the skeptics were entities in the Northwest known to favor Markets+ over EDAM, including Puget Sound Energy (PSE) and the Bonneville Power Administration.

“PSE is concerned that this proposal still leaves significant uncertainty with regard to achieving meaningful independence, does not ensure sufficient near-term independence of the RO from the California Independent System Operator, and does not provide a clear line-of-sight to Option 4 [which outlined a nearly complete transfer of CAISO functions to the RO] or a viable, broad, independent Western regional transmission organization footprint that includes California,” PSE said in its comments on the draft plan.

BPA officials expressed a similar view during a Nov. 4 workshop and follow-up press briefing to discuss the status of its day-ahead market decision process. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.) They noted the agency’s preference for Pathways’ Option 4, questioned whether the RO would even adopt Option 2.5 and said Markets+ already offered the governance option that “satisfies” its needs.

“We have an option that’s no longer hypothetical. It is a real option that has a real independent market governance structure that satisfies us, and that’s what we’re measuring everything else against,” Rachel Dibble, BPA vice president of bulk power marketing, said during the briefing.

EDAM supporters have argued the Pathways Step 2 plan represents the incremental step needed to move the West to a regionwide market that includes California.

“We believe that the Step 2 proposal is a logical ‘next step’ for markets for the Western Interconnection,” said Jim Shetler, executive director of the Balancing Authority of Northern California (BANC) and a member of the Launch Committee. “The concept of phasing the evolution of market services with participation on a voluntary basis is an approach that has worked successfully for the West and is consistent with BANC’s strategic vision. BANC is happy to support this next phase of the Pathways process.”