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December 3, 2024

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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.”

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Lame Duck Congress Could be Last, Best Chance for Permitting Reform

WASHINGTON — Both Sen. John Hickenlooper (D-Colo.) and former FERC Chair Neil Chatterjee (R) see the current lame duck Congress as having the best, possibly last chance to pass the Energy Permitting Reform Act of 2024 (S. 4753) and get it to President Joe Biden’s desk before he leaves the White House.

“The bill that’s sitting there right now, I think we can get that passed,” Hickenlooper said Nov. 13 during a forum hosted by Heatmap News at the Shaw Brewpub & Kitchen. “I’m not saying we’re going to, but I’m saying I think we’ve got a very good chance of Republicans and Democrats lining up [and] saying, ‘Alright, I don’t like a lot of this, but we need it.’ And I think both sides might hold their nose, and we might be able to get the thing through.”

Chatterjee, now a senior adviser at D.C.-based law firm Hogan Lovells, is less optimistic. But he said, “If we don’t get it done in the lame duck, it spills into next year, and you’re not going to get a lot of Democratic support to pass a permitting reform bill, and Republicans are not going to abolish the filibuster to pass legislative permitting reform. … Republicans are not going to overturn the birdbath to do legislative permitting reform.”

Authored by Sens. Joe Manchin (I-W.Va.) and John Barrasso (R-Wyo.), EPRA would double the target for renewable energy on public lands from the 25 GW already permitted to 50 GW no later than 2030 while also cutting the time allowed for filing legal appeals against federal decisions on energy projects from six years to five months.

It would also require RTOs and ISOs to collaborate on plans for interregional transmission and allow FERC to step in to permit interregional transmission projects after one year if a state delays or denies a permit, even if the project has not been designated as being in the national interest. (See Manchin-Barrasso Permitting Bill Would Give FERC Transmission Siting Authority.)

The Senate Energy and Natural Resources Committee passed the bill 15-4 on July 31, but it has yet to go before the full Senate. Hickenlooper is a member of the committee and voted for the bill.

While energy industry trade groups have largely supported the bill, environmental organizations have opposed it. But Hickenlooper sees the lame duck session as an opportunity for an “alignment of self-interest” between Democrats and Republicans, industry and environmentalists.

“Most of the environmental organizations recognize that if we’re going to successfully address climate change, we’ve got to get transmission lines,” he said. “We can’t spend 20 years permitting transmission lines. We’ve got to figure out how to make sure we do that in a way that protects the environment, protects [the] cultural heritage of these sites, but we’ve got to go faster. … The sense of urgency that we have is not nearly sufficient. …

“If we miss the chance with the Barrasso-Manchin bill, we’re still going to have to do all this work,” Hickenlooper said. “We’re just going to do it six months or a year or two years down the road, and it just puts us further away from beginning to address the issue.”

IRA vs. Tax Cuts

Hickenlooper and Chatterjee also were cautiously optimistic that the clean energy tax credits and incentives in the Inflation Reduction Act would not be sacrificed to pay for extending the tax cuts passed in 2017.

Hickenlooper’s main argument was that the new working-class voters in the Republican Party are among those benefiting from the clean energy manufacturing jobs the IRA is creating. “Rolling back those efforts for the simple purpose of giving another tax break to the publicly traded stocks of America doesn’t seem constructive,” he said.

Dismantling the IRA will create more uncertainty and disrupt business plans, he said, and such unpredictability could leave businesses not knowing “whether anything that’s agreed to is going to stay the same for more than two years.”

Chatterjee said he believes that even with Republican control of the House of Representatives and Senate, extending the 2017 tax cuts and rolling back the IRA through a single budget reconciliation bill could require more political capital than the GOP can muster.

Budget reconciliation is a legislative maneuver under which a budget bill can be passed with a simple majority vote in both houses as opposed to the three-fifths usually needed for such legislation. Both the 2017 tax cuts and 2022 IRA were passed via budget reconciliation.

Sen. John Hickenlooper (D-Colo.) | © RTO Insider LLC

But, Chatterjee said, in the Republicans’ new “populist working-class party, there’s not necessarily unanimity around the idea of extending corporate tax cuts at the expense of exacerbating the deficit. … I think [President-elect Donald Trump] and Republican leaders in Congress will leverage their political capital to get that piece of it done. But then to layer on IRA repeal on top of it, or IRA modifications to pay for it, at that point individual lawmakers start to have tremendous influence,” he said.

While the Republicans might have enough votes to roll back the IRA’s tax credits for electric vehicles, other incentives — for clean hydrogen, carbon capture or tech-neutral clean energy — could have individual supporters. “The end result is things get heavy, and they get tough to pass,” Chatterjee said.

At the same time, Chatterjee expects that former Rep. Lee Zeldin (R-N.Y.), Trump’s nominee to head EPA, will roll back the Biden administration’s regulations aimed at reducing greenhouse gas emissions from power plants and automobile tailpipes, but “in a thoughtful way that focuses on rational outcomes.”

“He may pursue a deregulatory agenda but do it in a way that is respectful and listens and brings different stakeholders to the table,” Chatterjee said. “I think that’s a good thing.”

‘Deep Uncertainty’

Hickenlooper and Chatterjee also are thinking similarly about the need to depoliticize the debate around climate and energy issues as lawmakers and regulators face the impacts of increasingly frequent and severe extreme weather, while meeting growing power demand from artificial intelligence, data centers and new manufacturing.

Trump may call climate change a hoax, Hickenlooper said, but “that’s not going to stop me from trying to go out and make the argument that if you live in Florida and you look at how you’re going to get insurance for property, you better look pretty closely right now because it’s now the states … [that] subsidize people’s property casualty insurance.”

If available at all, home insurance rates have skyrocketed in Florida and in other states that have experienced repeated extreme weather events. As a result, many homeowners have to rely on state-subsidized programs.

“We Democrats and Republicans and independents have to start finding ways to get this in the media and talking about it in real time,” Hickenlooper said.

Chatterjee sees the potential for bipartisan action on electricity demand growth. Neither party has, thus far, “fully grasped what this coming surge in demand means,” he said. “I think there is universal agreement amongst parties that we need to win the AI race against the Chinese Communist Party for national security purposes … and power will be the key to winning that AI race.”

But, he said, political and business leaders will need to do a better job of explaining those imperatives to the public, which could be faced with “increased consumer prices or potential threats to resource adequacy and reliability or backsliding on our decarbonization goals.”

Democrats will have to accept the need to keep fossil fuel plants online, and Republicans will have to accept that meeting new demand will require both an aggressive deployment of renewable energy and new transmission lines, he said.

“I actually think we are on a precipice of a moment in which, because of AI, because of investments in domesticating the supply chain for the clean energy future … we are on a trajectory to where red supply can feed blue demand,” Chatterjee said. “We are at a tipping point where we can take politics out of the clean energy transition and decarbonization and actually focus on collective solutions.”

Hickenlooper said getting buy-in from American consumers will require setting out a clear plan for the transition.

“I don’t understand how we got so far down the road without any kind of plan,” he said. “It’s hard to imagine the American people sacrificing and paying more for energy … if they can’t see where it’s leading and what the next sacrifice is and what their benefits are; the money they are going to [save].”

Like Chatterjee, Hickenlooper says all generation technologies will be needed. But even with a plan, a key challenge will be “making decisions under deep uncertainty. … That’s what we’re going to have to do: make decisions when there are, in many cases, not enough facts.”

“We don’t have enough information to really have the confidence our decisions need,” Hickenlooper said. “But we have to keep making decisions under deep uncertainty because we do not have the time. We don’t have the luxury.”

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NERC Sees ‘Reasons for Optimism’ as Winter Approaches

North America’s electric grid faces “familiar challenges” this winter but is also displaying “good reasons for optimism” heading into the cold months, NERC staff said while presenting the ERO’s newly release 2024-2025 Winter Reliability Assessment. 

The assessment, released Nov. 14, covers December 2024 through February 2025. It was developed over “several months of work with the regional entities and industry, and reviewing projections for demand and resources and the preparations that are been put into place for this upcoming winter,” NERC Manager of Reliability Assessments Mark Olson said in a media briefing.  

While the report did not identify any grid areas as facing high risk of insufficient operating reserves in normal peak conditions, it found multiple areas face elevated risk of energy shortfalls during “extreme winter conditions extending over a wide area.” All or part of most regions were mentioned as facing shortfall risks, including Texas, SPP, MISO, PJM, NPCC and SERC. 

“Winter demand forecasts … are elevated across most areas that we look at,” Olson said, noting demand is projected to rise at least 2% over last winter in most assessment areas. “It’s a significant jump from last year, and that was a big jump from the year before that.” 

The report also called out generation retirements in some areas as a factor in potential shortfalls. For example, MISO has experienced over 5 GW of reductions in coal and natural gas-fired generation from winter 2023/24. In MRO’s SaskPower subregion, coal generation capacity has fallen 140 MW (though offset by increases in gas generation capacity), while dispatchable thermal generation capacity “has declined by 2.6 GW from last year” in NPCC-New England and nearly 1 GW in the portion of SERC Reliability’s territory that includes North and South Carolina. 

Even in areas where dispatchable generation has increased — mostly through installation of gas generation — the growth has not always kept pace with new demand. This was the case in Texas, where dispatchable resources have increased by 1 GW since last year as demand rose more than 2 GW. Although solar and wind capacity have grown by 3 GW, the report noted these resources may have limited use in times of extreme cold weather. 

Limits on natural gas pipeline capacity were also noted to affect PJM, as well as NPCC’s New York and New England subregions. NERC cited “ongoing concerns with natural gas production and delivery in extreme conditions.”  

Balancing these concerns, the report also observed significant action by industry and regulators to address the systemic issues revealed by the winter storms of 2021 and 2022. In the media call, Olson said “there’s a lot of information to be gained from the things that went right in the January 2024 Arctic cold blast.” FERC and NERC’s joint report, issued in April, said the grid’s performance last winter demonstrated significant progress from previous years. (See FERC, NERC Review January Winter Storm Performance.) 

NERC staff also noted the ERO’s ongoing development of requirements for cold weather preparations by utilities, with EOP-012-2 (Extreme cold weather preparedness and operations) taking effect last month and its successor expected to be completed by next year. (See NERC: Board’s 321 Authority on the Table for Cold Weather Standard.)  

While Olson acknowledged the challenge of quantifying the effect of the standard on grid reliability, he said the report’s authors could consider the winterization requirements’ impact on non-fuel-related generator outages. He added that utilities’ preparations ahead of the standard’s effective date could be seen in the January winter storm, which NERC took as a positive sign for the report. 

‘Natural Gas Remains Essential’

In their reactions to the assessment, grid stakeholders focused on its information about energy sufficiency and resource retirements. In a press release, Todd Snitchler, CEO of the Electric Power Supply Association, said the assessment “once again underscores the serious power supply challenges facing our nation.” He added dispatchable generation resources will be key to ensuring reliability throughout the winter months. 

“Natural gas remains essential to ensuring a reliable system,” Snitchler said. “Generators and our partners in the natural gas value chain have taken meaningful action to address issues faced during recent storms and to enhance gas-electric coordination. As they do every year, our member companies take significant steps to prepare for winter operations and help ensure optimal performance.” 

Jim Matheson, CEO of the National Rural Electric Cooperative Association, also weighed in, emphasizing the danger that energy shortfalls pose to “the health of local communities and … the American economy.” 

“Demand for electricity is skyrocketing across America, and supply is not keeping pace. And flawed public policies that focus on shutting down always available power generation are compounding this problem,” Matheson said. “This report clearly highlights the need to swiftly implement a pro-energy policy agenda with a focus on affordability and reliability for American families and businesses. Smart energy policies that keep the lights on are more important than ever.” 

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FERC Approves JTIQ Framework, Cost Allocation

FERC on Nov. 13 approved tariff revisions and modifications to the joint operating agreement between MISO and SPP that will enshrine a structural and cost-allocation framework for the five 345-kV projects in the RTOs’ $1.6 billion Joint Targeted Interconnection Queue (JTIQ) portfolio (ER24-2798, ER24-2825). 

In a 4-0 decision (in which Commissioner Judy Chang did not participate), the commission found the proposed revisions to the RTOs’ generator interconnection processes and pro forma GI agreements in their respective tariffs and Joint Operating Agreement complied with its rules “by helping to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.” 

FERC said the proposed allocation of 100% of the JTIQ portfolio’s cost to interconnection customers is consistent with the cost-causation principle and allocates costs at least roughly commensurate with estimated benefits. The commission said the JTIQ study addressed transmission system limits preventing the interconnection of future generation capacity, thus benefiting all interconnection customers. 

“Interconnection customers are the primary beneficiaries of the JTIQ upgrades, and therefore the proposed allocation of 100% of the capital costs … to interconnection customers when fully subscribed is just and reasonable,” FERC said. “The RTOs also have shown that the JTIQ upgrades do not provide sufficient benefits for load in either RTO to qualify as transmission projects selected in the regional transmission plan for purposes of cost allocation.” 

MISO and SPP will now take the JTIQ portfolio to their respective boards’ upcoming meetings for their approval. Both boards meet in December. 

The RTOs expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to offset about 25% of the portfolio’s capital costs. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) 

Commissioner Mark Christie wrote a concurring opinion, noting that the JTIQ projects would not have been selected in the RTOs’ regional transmission plans. 

“These projects are not designed to serve load, i.e., consumers, with optimal solutions to identified reliability concerns or economic drivers,” he wrote. “Rather, the primary purpose of these projects is to provide interconnection customers — generation developers, primarily wind and solar — with more interconnection opportunities. Accordingly, it is appropriate that the primary funding for these projects is from the generation developers themselves, as they are the primary beneficiaries.” 

Christie said the order establishes that the benefits to load meet the cost-causation principle, justifying the RTOs’ proposal that load provide backstop funding for the portfolio. He said the funding mechanism is only just and reasonable with the GRIP funding covering 25% of the capital costs. 

“Without this funding, it would be unjust and unreasonable to allocate to load any of the [portfolio’s] costs,” he said. “These projects were not designed to serve load, plain and simple, and if there were no funding, the JTIQ proposal would not be acceptable.” 

Aubrey Johnson, MISO’s vice president of system resource planning and competitive transmission, said in an email and on social media that the JTIQ is a “critical process” to add more generation. 

“It provides certainty to interconnection customers near the SPP-MISO seam and enables lower-cost energy in each region,” he said in extending his appreciation for SPP’s “strong collaboration and innovative thinking” that led to the “first-of-its-kind framework.” 

SPP’s Casey Cathey, vice president of engineering, said the grid operator is “thrilled” that FERC recognized the JTIQ’s long-term value and its future benefits to members and customers. 

“We’ve had a successful partnership with MISO for many years and look forward to building on that success with the JTIQ initiative,” he said in an email. “These transmission projects will be a significant step toward eliminating barriers and improving the efficiency and reliability of transmission between our regions.” 

The two RTOs began working on the JTIQ process in 2020 after several unsuccessful attempts to find joint projects to alleviate congestion on their seam. They conducted reliability, economic and generation-enablement studies and coordinated with stakeholders to develop transmission solutions to identify the JTIQ upgrades that unlocked generating facilities and aligned their interconnection processes to reduce restudies and delays. 

MISO and SPP say the projects, focused on their northern seam, are expected to enable 28 GW in generation additions. They said the generation projects were stymied by the massive amounts of interconnection requests; the lack of current system capacity to accommodate the requests; and the significant incremental cost of upgrades that interconnected individual clusters that would otherwise be obligated to pay for the upgrades under the RTOs’ existing “but for” cost-allocation frameworks. 

The backbone of network upgrades consists of five projects, cut down from the original seven: 

    • Bison-Hankinson-Big Stone South, 147 miles of new 345-kV lines in the Dakotas (MISO).
    • Lyons Co.-Lakefield Junction, 80 miles of new 345-kV lines in South Dakota and Minnesota (MISO).
    • Raun, a new 345/161-kV double circuit and rebuilt 161-kV lines near Omaha, Neb. (MISO, SPP).
    • Auburn-Hoyt, new 345-kV lines in Nebraska (SPP).
    • Epanding and rebuilding a 345-kV substation in Sibley, Iowa (SPP). 
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Collaboration Needed to Address Large Loads, NARUC Panelists Say

ANAHEIM, Calif. — The power industry should encourage increased collaboration and transparency to address the many challenges posed by major new loads, presenters said during the National Association of Regulatory Utility Commissioners’ Annual Meeting from Nov. 10 to 13.

Data centers, hydrogen, transportation and other industries are all contributing to the rapid load growth, which can present both efficiency opportunities and forecasting challenges, according to Natalie Mims Frick, deputy department leader of energy markets and policy at Lawrence Berkeley National Laboratory.

Providing opportunities for conversations between stakeholders can help address those challenges, Frick said. She pointed to the North Carolina Utilities Commission’s recent ruling on Duke Energy’s consolidated carbon plan and integrated resource plan. One of the requirements is that the utility must provide frequent updates on load growth, Frick said.

“Having regular conversations can be really useful about how to deal with the growth and where it’s happening,” Frick said. She added that another requirement the North Carolina commission imposed was requiring the utility to work with their large customers “to try and identify opportunities for efficiency or other resources, whether it’s flexibility or something else.”

“And I think that kind of feeds back into the loop forecasting, you know, making sure that there’s robust consideration of all of the opportunities for the large loads, whether it is through flexibility or demand response to reduce peak demand,” Frick said.

Forecasting from a data center and automation perspective will likely remain a challenge, given confidentiality around business strategies, according to Samantha Klug, enterprise sustainability development director of logistics real estate investor Prologis.

However, it would be helpful if regulators could provide a roadmap around electrification and sustainability incentives, Klug argued.

“Because then what we can do is forecast out these projects and where we want to do them based on those incentives, and when the timing for capital investment is right for us,” Klug said. “And so for us, it’s really the communication between stakeholders.”

In a separate panel discussion, Farah Mandich, presidential sustainability executive at the General Services Administration, argued that transparency is important to help “people understand why the utilities and commissioners are making some of the decisions they do.”

Mandich added that thinking about customers’ needs as an asset, instead of just a problem to solve, is a good “mindset to be in.”

“The federal government is a longstanding existing customer. We are electrifying loads, but we’re not going to be causing the type of growth that you know a data center necessarily is in one given place, but that means that our buildings could potentially be an asset for load flexibility,” Mandich said. “And so thinking about how to bring customers into that conversation up front is really important, because it’ll take us a while to figure out how to do that in our own buildings and work with the utilities effectively.”

Jeff Riles, director of energy markets at Microsoft, noted that customers, regulators and utilities are all cooperating more frequently now than a few years ago. However, he said that there are challenges, including mistrust around growth of the data center industry.

“There’s a real concern about what’s speculative and what’s real,” Riles said. “And there’s a need to make sure that we’re showing up and helping them address the problem of what is speculative and what’s real. And so that’s been another reason why we have begun to engage more directly in a lot of these regulatory proceedings.”

He added that engaging in forums like NARUC “is new for us as an industry, and so we really appreciate the opportunity to have this collaboration. But I will just say we’re growing up right along with you in terms of how we engage in these processes and procedures.”