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November 27, 2024

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MISO Draws in Experts for Probabilistic Planning Symposium

CARMEL, Ind. — MISO further embraced the industry’s move to chance-based transmission planning by hosting a Probabilistic Planning Symposium at its headquarters.

The grid operator and consulting firm Energy and Environmental Economics pulled together stakeholders, other RTO planners, researchers and tech representatives to probe prospective planning methods and fret over the shortcomings of current practices Nov. 19-20.

Director of Economic and Policy Planning Christina Drake said when she joined MISO, planning was carried out on a relatively gradual timeline compared to the urgency today.

“We’re seeing these loads come on quicker than we can keep up,” she told attendees.

Drake said of late, MISO is having “friendly but frank” conversations with companies whose building goals are stymied by the limits of today’s transmission capacity.

She said just a few years ago, MISO was met with skepticism that its third, most aggressive planning scenario — which predicted electrification stimulating significant demand — would ever come to pass.

MISO announced earlier in November that it will revise its three, 20-year transmission planning futures — which envision the clean energy transition at a walk, a jog and a run — to be more in touch with recent realities of surprising load growth and accelerated clean energy goals. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.)

“And now we’re getting feedback that we think you’re near your top end on your load [predictions],” Drake said. “The drivers are changing. It’s no longer electrification; it’s things with hydrogen and data centers. That’s very different.”

Drake said the pace of change is so dramatic that MISO’s planning modeling is becoming unsolvable. “Our tools have never seen this. It’s pushing our models to the brink,” she said. “Now we’re projecting things 10 years faster.”

SPP Manager of Transmission Planning Kirk Hall seconded experiencing trouble trying to produce realistic models.

“We’re having to constantly add fictitious equipment … just to get our reliability models to solve,” he said.

“If you’re asking if the probabilistic planning tools are sufficient? The answer is no,” NYISO Director of System Planning Yachi Lin said.

Lin said New York’s past 35 years contained little in the way of transmission planning. Recent years, on the other hand, have contained about $15 billion in transmission and distribution investment, she said, owing to the state’s progressive climate goals.

Lin said New York City alone has an “acute” problem of having to retire several aging, combined cycle units, while new, zero-emission generation needs to occupy as little acreage as possible. She said advanced technology is years away, with a “big gap of getting there.” Lin likened transmission planning around those unknowns to layering up slices of Swiss cheese.

“There are holes, we know. But hopefully, if you have enough slices, you can cover the gaps,” she said.

Drake said building an economic model takes an amount of work that’s often not appreciated. She said it’s a level of challenge that’s on par with delivering a baby.

“It took a solid nine months, and there was a lot of crying and pain in the middle,” she joked of creating a successful model.

Drake added that just to get a model to solve today takes an “intense” effort. She said she felt like bringing planners a “Gatorade and a towel” after they’re successful.

ERCOT Power Systems Engineer Eric Meier also said that there aren’t any tools “off the shelf” today that can effectively evaluate probabilistic planning.

Drake said grid planners’ challenges are compounded by trying to anticipate yearly bouts of increasingly extreme weather and generation outages.

“This is new territory for all the RTOs,” she said.

Benjamin Hobbs, Johns Hopkins University | © RTO Insider LLC

Drake said extreme weather instances are driving an “insatiable” need to improve interregional transfer capability, evidenced by MISO’s new interregional studies with SPP and PJM.

During the symposium, grid planners named other obstacles to identifying the most useful transmission projects decades in advance.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said load growth is the greatest uncertainty for today’s planning.

“It’s astronomical — I don’t know what word I want to use. It’s so large, and it’s so unknown,” Asah said.

Asah also said too-slow regulatory processes and seized-up supply chains are sources of anxiety. “They are a big deal. They keep me up at night,” she said.

However, Asah said there’s reason for hope. She said MISO is building a new planning model designed to be more responsive so MISO more easily can incorporate stakeholder suggestions and influence the model.

“I want to end on hope instead of the things we can’t do yet,” she said.

Lin said retaining a planning staff is becoming more challenging with stiff competition between planning organizations. “It’s a friendly competition among the ISOs/RTOs. And that’s great, but we always want to make sure our people are taken care of,” she said.

Climate Unknowns

MISO dedicated panels to climate change, a little-used phrase among the politically agnostic grid planner.

Argonne National Laboratory engineer Neal Mann said the lab’s projections of future weather patterns across a range of scenarios through midcentury and end of century seek to predict the more frequent heating and cooling degree days in addition to risks like flooding.

Mann said planners might want to “use their neighbors like a battery” to tap into their supply when they fall short.

The Electric Power Research Institute’s Parag Mitra said EPRI’s Climate Resilience and Adaptation Initiative (READi) collaborative model helps planners make decisions that will make the system more durable against ever more dangerous weather. Mitra said planners need to have a good understanding of how weather can affect assets.

Christina Drake, MISO | © RTO Insider LLC

Con Edison’s William Gunther said his utility is analyzing future multiday wind lulls and high midday solar output that is squirreled away in storage for later use. He said a Con Edison climate vulnerability study delved into how high substations need to be positioned due to sea level rise as well as the potential for undergrounding lines when temperatures are too hot for transformers to be in the open air.

Mitra said while there is a need for scenario-based planning that draws on probabilities of extreme events, it’s also valuable to analyze extreme events after the fact to pinpoint where conditions began a downward slide. He said demand response also can play a role in climate resilience.

But University of Michigan Professor Michael Craig said he discouraged planners from assigning climate disaster probabilities for planning purposes.

“When we think about climate change, I want to advise against using probabilities. Because we do not know … a meaningful probability of future climate scenarios,” Craig said. “Climate change is not a problem for 30 years from now; it’s increasing extremes today and tomorrow and the year after.”

Instead, Craig advocated stress testing solutions in modeling against wide-ranging degrees of extreme heat, extreme storms and extreme drought.

“It’s not like we hit 2050 and it turns over. Every year, those dice get loaded; every year you might have more extremes,” he explained.

New Analytics

Johns Hopkins University professor Benjamin Hobbs advised grid planners to adopt stochastic programming, which mulls multiple scenarios simultaneously and uses decision trees to come up with the most beneficial investments. He said MISO comes close to stochastic planning with its futures-based planning.

“The grid that you’re building needs to be nimble to be adaptive to economics, policy, climate,” Hobbs said.

Hobbs said a stochastic approach is useful for MISO, which contains states with and without carbon limits and renewable portfolio standards.

He said MISO could plug in variables like technological advancements, load growth, fuel costs, capital costs and carbon costs and limit potential solutions by constraints like siting limitations, emissions reduction standards and Kirchoff’s circuit laws.

Bilal Khursheed, Microsoft | © RTO Insider LLC 

Hobbs said he wasn’t suggesting planners could “naively” load up variables and expect a model to pinpoint the best grid solution. “What you’re getting from the model is suggestions,” he said. “All forecasts are wrong, so it’s important to consider a wide range of them.”

Iowa State University professor James McCalley made a case for adaptive co-optimized expansion planning, which shows the costs of grid expansions based on a specific future build (or a core) and the costs of adaptations to the original plan that may be necessary.

McCalley said the adaptive approach is a “cousin” of stochastic planning but not the same because the method is designed to show costs through time.

“I would make the case that both of these methods are useful tools in a planner’s toolbelt to understand the best way forward,” he said.

McCalley said adaptive co-optimized planning shouldn’t be a substitute for the PROMOD commitment and dispatch model, Siemens’ PSS®E Power Simulator or EPRI’s Electric Generation Expansion Analysis System. Rather, he said the method should be layered over them as an application to guide decisions.

McCalley said planners should continue to use their deterministic tools and introduce new, probabilistic analyses until they form a “single integrated method of doing the work.”

McCalley said he knows firsthand from his experience as a PG&E planner in the late ‘80s that deterministic planning leaves much to be desired. He recalled being grilled over planning practices in front of the California Public Utilities Commission.

“Probabilistic planning isn’t going to be a quantum leap for anyone. It’s going to be a journey, and we need to start now,” Mitra said.

AI Assistance

“Our grids are facing pressures like they’ve never faced before,” Microsoft’s Bilal Khursheed agreed, but offered AI as a means to lessen the tension.

Khursheed said the recent leaps in AI can better balance supply and demand in real time, improve resource utilization, assist in resource planning, better predict maintenance, provide the best insights to operators and speed the clean energy transition, among other things.

RaeLynn Asah, MISO | © RTO Insider LLC

“These advancements aren’t incremental. They’re truly transformational in nature,” he said.

Khursheed said grid planners should think of AI as “the brain of modern grid flexibility,” the internet of things as “the eyes and ears of the grid” and the cloud as “the backbone of the ecosystem.” He also said planners first must consider the “balancing act” of leveraging the most they can from existing assets before deciding to physically expand the grid.

“It’s not just about building more. It’s about spending only when we absolutely have to,” he said.

Khursheed said AI’s sophistication can defer capacity investments by harnessing virtual power plants to provide flexible resource adequacy. He said Microsoft recently worked with a “large western European” transmission operator and found that it could cut “overcommitted fossil fuel resources” by 17 GW over the length of the pilot program through high-performance AI computing that helps operators make better use of cheaper, carbon-free resources.

The pilot saved the operator “millions of Euros,” Khursheed said, and the topology optimizer is set to be rolled out on a large scale in the footprint.

Khursheed said transmission operators are shifting from being “reactive” when facing storms and temperature extremes and using generative AI to figure out earlier which assets are likely to take a hit and what transfer capability stands to be the most helpful.

However, Khursheed said Microsoft is risk-averse and thus far is making sure AI is providing more accurate data sooner to “drive levels of productivity we’ve not seen before” but not running the grid autonomously.

“There’s still a human-in-the-loop component,” he said.

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FERC Rules Against SPP Multiday Commitment Proposal

FERC on Nov. 21 rejected SPP’s proposed tariff revisions to implement a multiday economic commitment (MDEC) process, saying it introduces a potential gaming opportunity (ER24-2520). 

The commission agreed with the RTO’s Market Monitoring Unit that long-lead resources, such as coal plants, could intentionally lower their market offers below their actual costs to gain an out-of-economic-merit order and then receive a make-whole payment to which they would not otherwise be entitled. 

“SPP’s proposal would allow certain resources to unreasonably shift the risk that their costs are not recovered exclusively to customers, potentially leading to both inefficient market outcomes and gaming opportunities,” FERC said. 

The commission also said SPP had not adequately supported its assertion that its “analysis shows that [the proposed MDEC process has] the potential to create economic benefits to the market.” It said the RTO did not provide any information about the analysis or a “reasoned explanation” that showed the MDEC process would lower total production costs. 

“It is not clear how SPP’s proposal would result in a lower-cost commitment solution because long-lead resources could appear cheaper to the market than they really are, potentially displacing lower-cost resources and driving up market costs with no benefit to the market,” the commissioners wrote. 

SPP had argued that the proposed MDEC process would improve the methods by which long-lead resources, which account for about 34 GW of available energy, participate in SPP’s market. Currently, they cannot be committed in the day-ahead market, instead normally opting to self-commit as price takers. However, the increased prevalence of less expensive renewable and natural gas units has made coal units increasingly less economical to self-commit. 

Several public interest organizations protested SPP’s proposal, saying it would require the RTO to evaluate the economics of issuing commitment instructions to long-lead resources by comparing the expected production cost impacts of committing them before the day-ahead market closes using the real-time balancing market’s offers for all resources. 

“There was absolutely no evidence that the process proposed by SPP would actually work to reduce the uneconomic dispatch of coal resources in the market,” Earthjustice attorney Aaron Stemplewicz, who represented several public-interest groups in the proceeding, told RTO Insider via email. “The commission was correct to flag that it merely shifted risk from generators to the market and could easily have been manipulated to be a handout for uneconomic coal-burning power plants and other long-lead resources.” 

FERC’s order was without prejudice, allowing SPP or other grid operators to propose different MDEC processes. 

Cost-allocation Ruling Reaffirmed

FERC also rejected rehearing requests and sustained its previous approval of SPP’s tariff revisions allowing certain transmission facilities’ costs to be entirely allocated on a regional postage-stamp and cost-by-cost basis (ER24-1583). 

The commission modified its original order but reached the same result it did in May, when it found SPP’s capacity, flow and benefit analyses of the Sunflower Electric Power transmission facilities at the center of the proceeding provided benefits to the region as a whole. (See FERC Approves SPP’s Cost-allocation Revisions.) 

Several SPP transmission owners and municipal utilities and the Louisiana Public Service Commission filed rehearing requests of FERC’s order. They contended that the commission did not conduct the necessary cost-causation analysis and misapplied the “roughly commensurate rule” because it did not require a more granular, zone-by-zone benefits analysis of SPP’s proposal. 

FERC dismissed those arguments, along with others that claimed the commission failed to show that SPP’s capacity, flow and benefit criteria are linked to cost causation and that the order is “impermissible retroactive ratemaking.” 

Commissioners Mark Christie and Lindsay See filed separate concurring opinions, with both concurring only in the result of the proceeding and agreeing that the deciding factor for them was the support of the SPP Regional State Committee, which “has historically had a unique and authoritative role representing the states in SPP,” Christie said. 

“For me, the RSC’s unique role in representing the SPP states in difficult cost-allocation matters like these resolves this close case on the side of approval,” See wrote. 

In a Nov. 20 letter order, FERC also accepted SPP’s tariff revisions to calculate real-time balancing market (RTBM) prices should the system fail for more than 12 dispatch intervals and to extend the notification period for price corrections (ER25-71). 

The grid operator will use the day-ahead market’s LMPs, marginal congestion components and marginal loss components for RTBM settlements. The mechanism will accurately reflect prices had the RTBM system results not been able to calculate LMPs. 

The notification period is extended from five calendar days to five business days. 

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Amid Praise for Pathways Step 2 Milestone, Skeptics Remain Unmoved

The West-Wide Governance Pathways Initiative drew praise from many quarters Nov. 22 when its Launch Committee voted to approve its “Step 2” proposal to create an independent “regional organization” to oversee CAISO’s Western electricity markets. 

But it was quickly apparent the development — over a year in the making — is unlikely to shift views of those entities that remain skeptical about joining a market operated by CAISO and instead favor SPP’s Markets+. (See related story, Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding.) 

Counted among the strongest supporters of the final proposal, which was released Nov. 15, were the state utility regulators and energy officials largely responsible for launching the Pathways Initiative in July 2023. 

“It was only last summer that my colleagues and I across the West wrote a letter expressing our hope for an independent regional organization to oversee an expanded day-ahead market that includes California,” California Energy Commission Vice Chair Siva Gunda said ahead of the Launch Committee’s vote. “Since then, it’s amazing to watch how some of the brightest and most dedicated experts across diverse sectors in the West have come together to lay the foundations for this regional organization.” 

“The Launch Committee, the stakeholders — you stepped up to the request in the letter, working together, had success for [Pathways] Step 1, and [are] now voting on this foundational document that could really achieve the broad idea that was in our request,” New Mexico Public Regulation Commission Chair Pat O’Connell said. 

Oregon Public Utility Commissioner Letha Tawney said she appreciates the proposal “centers consumers” and provides “the opportunity for benefits in a different way that is exciting.” 

“At the end of the day, we have to be delivering for consumers this essential service at a price they can manage,” Tawney said. “That is what underpins the Western economy, but it also is what delivers for our most vulnerable customers, and I so appreciate the Launch Committee digging in and figuring out how to deliver on that fiduciary duty that the regulators put out to the region and asked you to help us solve.” 

Michele Beck, director of the Utah Office of Consumer Services and a Launch Committee member, said she began participating in the Pathways effort “defensively,” which is how she thinks consumer advocates likely approach any such regional activities. 

“Working with this group helped me to build confidence in the effort and really optimism about the outcome, as I saw a genuine focus on the public interest, which has been mentioned before. I think our proposal really has the greatest public interest protections that we see in any regional proposals out there,” Beck said. 

Beck acknowledged that Pathways still has a lot of work ahead of it in the next year and that Step 2 did not address some “big issues” that “were properly” not within its scope.  

“But this is consistent with the incremental approach that we’ve been taking here in the West, and [Step 2] remains a very important milestone,” she said. 

Committee member Brian Turner, director of Advanced Energy United’s regulatory engagement in the West, said the Step 2 “proposed governance structure recognizes the electric grid is evolving and a greater diversity of resources and customers and load-serving entities and solution-providers all have an essential interest in efficient markets and the affordability and reliability they bring.” 

Nonvoting committee member Chrystal Dean, vice president of enterprise portfolio management at the Western Area Power Administration (WAPA), noted that WAPA’s Sierra Nevada region recently announced it will begin negotiations toward full participation in EDAM through its membership in the Balancing Authority of Northern California and that its Desert Southwest (DSW) region will partner with Arizona G&T Cooperatives on a study to assess the CAISO market’s benefits for the DSW balancing authority area. (See WAPA Sierra Nevada Region to Advance with EDAM and Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.) 

“Both of these efforts underscore WAPA’s commitment to exploring new opportunities like those described in this Pathways Step 2 proposal, and we are really excited to see that these steps will help WAPA continue to make decisions that align with our market principles,” Dean said. 

Committee co-Chair Kathleen Staks, executive director of Western Freedom, said that as a representative of commercial and industrial electricity customers, she’s seen a “remarkable increase in the number of companies that are actively engaged and paying attention and wanting to learn, and so I think they are. We’re seeing a sector that’s getting very excited about the opportunities to participate.” 

‘No Guarantee’

But the Pathways milestone failed to dispel skepticism about the effort from entities still firmly situated in the Markets+ camp. 

Britney Morgan of Arizona Public Service, the sole committee member to abstain from voting on the proposal, said while Step 2 would incrementally improve the independence of the governance of CAISO’s WEIM/EDAM, it “does not achieve independent governance, which was the ask of the regulars more than a year ago.” 

“Under Step 2 … CAISO remains as the market operator, which perpetuates existing inequities between market and state participants,” Morgan said.  

Rachel Dibble, vice president of bulk power marketing at the Bonneville Power Administration, acknowledged “the significant amount of work” the Launch Committee and work group put into the Phase 2 proposal but said the plan fell short of BPA’s expectation for fully independent market governance, administration and operations for CAISO’s markets. 

Dibble reiterated three concerns BPA has recently expressed about the proposal: that it will 1) leave the RO under a single, integrated tariff shared with CAISO; 2) leave market operations, supporting staff and management functions under CAISO board authority; and 3) maintain the ISO as the counterparty in contracts with market participants.  

In an email to RTO Insider, Lauren Tenney Denison, director of market policy and grid strategy at the Portland-based Public Power Council (PPC), voiced a view that aligns with BPA’s. 

“Individual PPC members will evaluate the risks and benefits of this proposal in making their market participation decisions,” Tenney Denison wrote. “That said, for PPC and most of our members, the Step 2 proposal advanced by the Launch Committee falls well short of our expectations for independent governance. The limited creation of a ‘policy setting’ organization that continues to rely heavily on CAISO in many areas — financial, regulatory and staffing, for instance — will not establish a regional organization or market administrator that is independent. While potential future evolution is possible, there is no guarantee this will occur.”

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Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding

The West-Wide Governance Pathways Initiative’s Launch Committee voted Nov. 22 to approve the group’s “Step 2” proposal to create a new Western “regional organization” to provide independent oversight for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The proposal passed on a nearly unanimous vote, with one abstention by committee member Britney Morgan, a regulatory consultant with Arizona Public Service, who said while APS agreed the plan represented “incremental” progress toward the goal of bringing independent governance to CAISO’s markets, it did not meet the utility’s standard for independence.

APS has been a funder and strong supporter of SPP’s Markets+, which is competing with EDAM for participants.

Other committee members were effusive in their praise for the proposal, with some citing that incrementalism as benefit for a Western region that has been historically suspicious of developing a centralized market, while others noted the “diversity” of interests that came together to develop the plan.

“Because the proposal creates a Western entity staffed by Western people, we strongly support this proposal as the best option for all of us,” said committee member Ben Otto, speaking on behalf of the Northwest Energy Coalition, an ardent EDAM supporter.

RTO Insider will follow up with a more detailed story about the vote and related discussion.

The vote came two days after Pathways received a significant financial boost from the U.S. Department of Energy, which awarded nearly $1 million to underwrite its efforts to establish a Western “regional organization” (RO) to oversee CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.

The award was issued through the Pathways Initiative’s philanthropy advisor Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.

The award was part of nearly $10 million the administration granted to six projects nationwide intended “to improve state and regional engagement in wholesale electricity markets.”

An abstract of the application Global Impact submitted to the DOE’s Grid Deployment Office shows Pathways applied for $985,109 over two years to “support stakeholder convening, materials development, facilitation and personnel costs to achieve the goals of Phase 3 of the initiative,” which will include “refinement and formalization” of the RO’s stakeholder process, creation of “final governance documents and tariff language” for the RO, and identifying and hiring of the RO’s board and initial staff.

The most recent spreadsheet posted on the Pathways website in August shows that six organizations have committed to fund the second and third phases of the effort, including Clean Energy Buyers Association, California Community Choice Association, Balancing Authority of Northern California, Western Freedom, Microsoft and Amazon.

The Pathways Launch Committee’s “Step 2” proposal released Nov. 15 said the RO, to be established next year, would start out with “limited staffing” on an estimated budget of $1.25 million to $1.5 million, which eventually could increase to $10 million to $14 million. (See Pathways Initiative Issues Final ‘Step 2’ Proposal.)

The proposal also said the committee recognized that startup funding for the RO likely will “be required before any market supported funding is available” and that due consideration “should be given to identifying funding that would not be considered as compromising [RO] board independence.”

“The recommendation is to consider sources such as DOE grant funding or ongoing support from the Pathways Initiative 501(c)(3) funding via Global Impact,” the Launch Committee wrote in the proposal. “There was little stakeholder comment on this recommendation, though general support existed.”

The award represents a sharp turnaround for Pathways, which earlier this year was rejected for $800,000 in DOE grants because the agency said it lacked details about the scope of activities to be covered by the funding, which would have been dispersed in $400,000 tranches over two years. (See Pathways Initiative Rejected for $800K in DOE Funding and Past Opponents Now See Legislative Pathway to CAISO Regionalization.)

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FERC Approves Adoption of Latest NAESB Standards

FERC on Nov. 21 agreed to a final rule ordering utilities to adopt the North American Energy Standards Board’s (NAESB) latest updates to its Standards for Business Practices and Communication Protocols for Public Utilities (RM05-5).

The rulemaking issued at the commission’s monthly open meeting requires utilities to implement version 004 of the standards starting 12 months after the publication of the final rule in the Federal Register. By this point entities must have implemented the cybersecurity standards; the rest must be adopted by 18 months after publication.

NAESB published and filed version 004 of the standards on July 31, 2023, following their development by the organization’s Wholesale Electric Quadrant (WEQ). FERC proposed adopting them in April of this year, saying their use “would enhance the electric industries’ systems and software security measures and improve efficiencies of certain business processes transactions.” (See FERC Proposes Adopting NAESB’s Latest Revisions.)

Version 004 modifies multiple existing standards from the suite:

    • WEQ-000: Abbreviations, acronyms and definition of terms
    • WEQ-001: Open access same-time information system (OASIS)
    • WEQ-002: OASIS Standards and Communication Protocol (S&CP)
    • WEQ-003: OASIS data dictionary
    • WEQ-004: Coordinate interchange
    • WEQ-005: Area control error equation special cases
    • WEQ-006: Manual time error correction
    • WEQ-008: Transmission loading relief (TLR) – Eastern Interconnection
    • WEQ-012: Public Key Infrastructure (PKI)
    • WEQ-013: OASIS implementation guide
    • WEQ-015: Measurement and verification of wholesale electricity demand response
    • WEQ-021: Measurement and verification of energy efficiency products
    • WEQ-022: Electric industry registry
    • WEQ-023: Modeling

Also included in the adoption is a new set of standards, WEQ-024 (Cybersecurity business practice standards). NAESB said the WEQ-024 standards “reorganizes existing NAESB cybersecurity business practice standards” in response to a recommendation from the Department of Energy and Sandia Labs after a 2019 assessment of the cybersecurity elements in a previous version of the standards.

FERC said it declined to adopt WEQ-010 out of consistency with its “past practice of not incorporating by reference … any optional model contracts and related documents because we do not require the use of such contracts.” In addition, the WEQ-025 standard has also been omitted, along with related changes to WEQ-000, because they use terms that are similar to FERC’s pro forma open access transmission tariff.

The commission said public utilities whose tariffs do not automatically incorporate all new NAESB standards without modification must submit compliance filings no later than 120 days after the final rule’s publication. Compliance filings must include two separate tariff records; the first must include a reference to the NAESB cybersecurity standards with a proposed effective date 12 months after publication, and the second must refer to all version 004 standards in the final rule with an effective date 18 months after publication.

Utilities must specify in their tariff records, for all of the NAESB standards adopted, whether the standard is incorporated by reference; if not, which tariff provision complies with the standard, and any standards for which the utility has been granted a waiver, extension of time or other variance.

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FERC Order 1920-A Wins Approval with Accommodations to States

WASHINGTON — FERC on Nov. 21 voted to approve Order 1920-A, which upholds most of the original’s changes to the commission’s rules on transmission planning and cost allocation while giving more consideration to states (RM21-17-001). 

Commissioner Mark Christie (R), who voted against Order 1920 when it was issued in May, joined the Democratic majority in issuing the revised order, which addressed his main criticism of the original: Transmission providers now will be required to file any cost allocation proposals agreed to by states in a region alongside their own for the commission to consider. 

The original order gave state entities six months to agree on a cost-allocation method for transmission projects, but planners could simply ignore it and file their own method. It represented a change from the Notice of Proposed Rulemaking that had drawn Christie’s support in the first place. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

FERC issues major orders like 1920 under Section 206 of the Federal Power Act, the same statute that covers complaints about utility rates and ISO/RTO rules. With Order 1920, FERC had to find that regional planning efforts around the country were leading to unjust and unreasonable rates and then come up with a just and reasonable replacement rate, Christie said at the open meeting. 

“The changes made today in Order No. 1920-A to the replacement rate set by Order No. 1920 go a long way [toward] restoring the state role to what the NOPR promised, and I am pleased to support these changes,” he wrote in a partial concurrence. “I express my deep appreciation to my colleagues for their willingness to engage in good-faith negotiations leading to these important changes to the replacement rate.” 

“This order builds upon an already strong Order No. 1920 and will further enhance the ability of state regulators to provide their important perspectives on the much-needed new transmission facilities our nation needs to ensure our grid can serve the significant growth in demand for electricity,” Chair Willie Phillips said. 

Other changes Christie applauded include a requirement that if a transmission provider wants to change a cost-allocation agreement after it has gone into effect, they will have to consult with state regulators. It also will allow the State Agreement Approach in PJM, which New Jersey used to plan connections for state-backed offshore wind, to stay in place under the new regional planning regime. 

Christie noted in his concurrence that “the requirement in Order No. 1920 that large corporate power-purchasing preferences must be a factor in planning long-term scenarios is explicitly removed. That was one of the most unconscionable, special-interest driven features of Order No. 1920, directing transmission providers to plan hundreds of billions of dollars of transmission projects to subsidize the power-purchasing preferences of huge multinational corporations and shifting the costs to residential and small-business consumers already struggling to pay their monthly power bills.” 

That means expensive transmission lines to connect corporate demand with resources they have contracted with will not be cost allocated to all customers in a region, he added. 

Commissioner David Rosner said he was proud to vote out a “bipartisan order” that makes meaningful changes to Order 1920 based on the rehearing requests but still fulfills the original’s purpose of identifying needed regional transmission infrastructure that makes the country more secure. 

“The need for this rule is urgent and obvious,” Rosner said. “In conversations I have had around the country these last few months in my new role, I have come to see that there is broad agreement that we have a pressing need for more infrastructure.” 

New large customers are looking to connect to the grid while the uses of electricity are expanding into new areas of demand, while the interconnection queues are overflowing with resources that Order 1920-A will help get connected to the grid, he added. 

Commissioner Judy Chang said Order 1920-A should get the country building major transmission lines. 

“Based on that experience, I think Order 1920 — and now Order 1920-A — is a very strong order, and substantially improves transmission planning and helps to solve the cost allocation problem that we’ve been talking about for the last 20 years,” Chang said.  

Failing to agree on cost allocation leads to a logjam of transmission projects that the new rule should help to break up, she added.

Commissioner Lindsay See (R) said she recused herself from participating in the order on the advice of FERC’s designated ethics official, but she has “been really encouraged by what I’ve heard about the process that led to it. This order involves some of the hardest and most important issues before the commission, [and] I’ve heard from my colleagues that it reflects many hours of serious discussion trying to understand different points of view. 

FERC had not published the text of the order by the close of business Nov. 21, so several stakeholders declined to comment until they had actually read it. 

But Grid Strategies President Rob Gramlich, who has long supported the kind of changes in Order 1920, said he liked that FERC is moving forward with the new planning and cost allocation rules. 

“The states that were concerned should be very happy,” Gramlich said. “It’s kind of a bipartisan, FERC-state kumbaya moment. No one got everything, everyone got something.” 

Christie’s concurrence cuts the legal and political risk, he added. 

“Hopefully most states lay down their arms and start participating in planning,” Gramlich said. 

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DOE Commits to Funding Gulf Coast, Midwest Hydrogen Hubs

The U.S. Department of Energy has announced $2.2 billion in funding commitments to two hydrogen hubs: the HyVelocity hub on the Gulf Coast and the Midwest Alliance for Clean Hydrogen (MachH2) hub in four Midwestern states.

The Nov. 20 announcement means the DOE so far has reached funding agreements with five of the seven hydrogen hubs selected in October 2023 to receive a combined total of up to $7 billion through the Infrastructure Investment and Jobs Act. (See DOE Designates Seven Regional Hydrogen Hubs.)

The previous agreements are with the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) hub in California; the Appalachian Regional Clean Hydrogen Hub (ARCH2); and the Pacific Northwest Hydrogen Hub (PNWH2). (See California Reaches Funding Agreement to Launch Hydrogen Hub; Pacific NW Hydrogen Hub Launched with 1st Round of Federal Funds; and Feds Launch Appalachian Hydrogen Hub.)

The two hubs still in funding negotiations with the DOE are the Heartland Hydrogen Hub in Minnesota, North Dakota and South Dakota and the Mid-Atlantic Hydrogen Hub in Pennsylvania, Delaware and New Jersey.

In the two new awards, DOE committed up to $1.2 billion to the HyVelocity hub, with an initial funding round of $22 million. The MachH2 hub will receive up to $1 billion in federal funding, including an initial allotment of $22.2 million. The initial funding will allow the hubs to launch, starting with a planning and design phase expected to last 12 to 18 months.

DOE’s Office of Clean Energy Demonstrations (OCED) will oversee development of the hydrogen hubs and decide whether to provide funding for the hubs to progress to the next stage.

It’s not clear what impact the incoming Trump administration will have on the hydrogen hub funding. When asked about potential funding impacts, a DOE spokesperson noted that OCED was established to oversee large and complex projects that can span 10 years or more. “The dedicated federal workers within OCED remain committed to this mission,” the spokesperson told NetZero Insider in an email.

Gulf Coast Hub

The HyVelocity hydrogen hub would be centered around Houston and serve the Gulf Coast region. The Gulf Coast already is the nation’s largest hydrogen producer, according to HyVelocity, which aims to be the largest hydrogen hub in the U.S.

The industry-led hub includes six core partners: AES Corp., Air Liquide, Chevron, ExxonMobil, MHI Hydrogen Infrastructure and Ørsted. As proposed, the hub would produce clean hydrogen by electrolysis of water and from natural gas coupled with carbon capture and storage. The plan also includes pipelines to connect production facilities to demand centers.

The clean hydrogen would be used for fuel cell electric trucks, industrial processes, ammonia production, refining and petrochemical production, and marine fuel, according to a project fact sheet. The total cost for Phase 1 of the Gulf Coast hub is $56 million, including the $22 million federal contribution.

Midwest Hub

The Midwest Alliance for Clean Hydrogen hub is eyeing project sites across Illinois, Indiana, Iowa and Michigan, with possible expansion into other states. The hub is in “a key U.S. industrial and transportation corridor,” according to the Alliance.

As proposed, the hub would produce more than 1,000 metric tons per day of clean hydrogen using diverse local energy sources such as renewable energy, natural gas and nuclear power, according to a project fact sheet.

“Our fleet of always-on nuclear power plants in Illinois is helping to power our economic growth with clean energy today and positions us to be a leader in the clean hydrogen future,” Illinois Gov. JB Pritzker said in a statement.

The Midwest hub consists of eight projects to be developed by nine entities: Air Liquide; BP; Constellation Energy; GTI Energy; Invenergy; Mass Transportation Authority – Flint; Michigan Department of Environment, Great Lakes and Energy; Midwest Hydrogen Corridor Coalition; and Nicor Energy Ventures (NEV).

The projects aim to decarbonize industries including heavy-duty transportation, manufacturing, steel and glass production, power generation and refining. Phase 1 of the Midwest hub will cost $51.7 million, with $22.2 million coming from the DOE.

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FERC Outlines Reliability Impacts from Colder Winter

Electricity and natural gas demand could be higher this winter because of lower expected temperatures than last year, and large parts of the North American electric grid face a “higher likelihood of tight supply and reliability issues during extreme winter conditions,” FERC staff said Nov. 21 while presenting the commission’s 2024-2025 Winter Energy Market and Electric Reliability Assessment.

NERC representatives also joined FERC staff for the presentation at the commission’s monthly open meeting, providing insights from the ERO’s recently released 2024-2025 Winter Reliability Assessment. (See NERC Sees ‘Reasons for Optimism’ as Winter Approaches.) Like NERC’s assessment, the FERC report covers December 2024 through February 2025.

Opening the presentation, Micah Gowen, of FERC’s Office of Energy Policy and Innovation, outlined multiple potential trouble spots during the winter months. The report highlighted the National Oceanic and Atmospheric Administration’s forecast for December through February, predicting lower overall temperatures across the U.S. compared to last winter.

Colder temperatures “could contribute to higher year-over-year natural gas and electricity demand,” the report said, though it noted that NOAA also suggested the southern and eastern parts of the country may experience higher-than-average temperatures, with as high as a 70% chance in some areas. In addition, Gowen noted that “all regions may face a higher likelihood of tight generation availability under extreme weather conditions.”

Drought, Wildfire Risks Persist

Additional weather-related influences include drought conditions and wildfire risks, both of which are expected to persist into the winter in multiple regions. NOAA’s three-month precipitation outlook shows droughts are likely to improve in the Pacific Northwest because of projected rains from La Niña but persist in the central U.S. and even increase in the Southwest and Southeast. This could limit the availability of hydroelectric generation in some parts of WECC’s territory, though the increased rain in some areas may help to balance this issue.

Wildfire risks are forecast to remain elevated into the early winter in Texas, Oklahoma and Southern California because of dry conditions and to continue through winter in Texas, where higher temperatures than the rest of the country are predicted. The persisting wildfire conditions could lead to public safety power shutoffs. On the other hand, mild temperatures could lower electric demand and “allow for greater system operator flexibility,” the report said.

Natural gas futures prices for the past three winters. Prices for 2024-2025 are average last traded futures prices for December, January and February. Previous winters’ prices are average settled futures prices. | Intercontinental Exchange

With natural gas production likely to “remain relatively unchanged compared to winter 2023-2024,” Gowen said, the expected higher demand for gas for heating and electricity generation has pushed natural gas futures prices higher at several hubs. The report quoted the Energy Information Administration’s forecast average production of 104 Bcfd, down 1% from last winter’s average but still 6% above the previous five-year average.

As of Nov. 14, futures contract prices at the national benchmark Henry Hub in Louisiana averaged $2.95/MMBtu for this winter, up from last winter’s average settled futures price of $2.61. Prices at the Algonquin Citygate Hub near Boston averaged $8.86, up from $7.61 settled last winter. The report noted that an additional influence on New England natural gas prices is high global LNG prices because the region heavily relies on imports during the winter.

Prices are also lower at several hubs, including PG&E-Citygate in Northern California, with average prices for this winter down 10% from last winter at $4.74/MMBtu, and SoCal-Citygate, down 3% at $5.02. The report attributed these declines to mild forecasted winter weather, higher storage inventories and increased hydroelectric generation.

Reliability Effects

Rakesh Batra, of FERC’s Office of Electric Reliability, discussed the supply and demand forecasted for each NERC region.

Citing NERC’s assessment, Batra said that all regions “have sufficient available resources and net transfers to meet their respective operating reserves under normal winter conditions,” despite higher electricity demand compared to last winter. However, he added that extreme events may drive demand higher or damage transmission and generation facilities, making serving demand more difficult.

Batra noted that NERC and other stakeholders have taken numerous steps since the winter storms of 2021 and 2022, including the passage of the cold weather standards EOP-011-4 (Emergency operations) and EOP-012-2 (Extreme cold weather preparedness and operations), both of which became effective Oct. 1. However, he also said that grid reliability could be impacted this winter by the ongoing restoration work from Hurricanes Helene and Milton, which hit the Southeast earlier this fall.

Commissioners reacted to the report’s warnings by encouraging stakeholders to make grid reliability a priority investment, including by accelerating compliance with the new cold weather standards. Commissioner David Rosner said that, although many of the new standards’ requirements will not become effective until next year, “the best time to comply with the 2025 deadline is today.”

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Powerex to Cancel Rights on PacifiCorp Tx System over EDAM Changes

Powerex intends to terminate a large portion of its rights on PacifiCorp’s transmission system in response to the utility’s plan to update its Open Access Transmission Tariff to align with CAISO’s Extended Day-Ahead Market (EDAM), the company said in a Nov. 14 paper that also warned the changes could cost the utility about $135 million in revenue.

Powerex argued in the paper that PacifiCorp’s expected tariff changes could lead to the utility using EDAM’s rules related to the distribution of transmission congestion rents to “effectively strip” its transmission customers of “the economic value of their transmission rights” — to the detriment of customers in both EDAM and SPP’s Markets+.

“Unfortunately, PacifiCorp has chosen to use its entry into EDAM to fundamentally redefine what it provides to its transmission customers in exchange for the transmission revenue it collects,” Powerex, the energy marketing arm of Vancouver, Canada-based BC Hydro, wrote.

The company’s contention potentially opens up yet another front in ongoing competition between EDAM and Markets+ and in the debates between each market’s supporters.

PacifiCorp’s plans already have led to Powerex providing a notice “to terminate the vast majority of Powerex’s long-term firm point-to-point transmission rights on PacifiCorp’s transmission system, for which Powerex currently pays over $42 million per year to PacifiCorp,” according to the paper.

However, despite the move to cancel the contracts, Powerex emphasized it will retain 200 MW of rights to ensure power flows in SPP’s Markets+ — a position it intends to fight for before FERC.

Jeff Spires, director of power at Powerex, told RTO Insider in an email that the company “continues to hold the long-term firm transmission rights it intends to use for Markets+ connectivity, and is committed to protecting these rights on the PacifiCorp system.”

Under PacifiCorp’s anticipated changes, transmission customers will face new congestion charges calculated in EDAM, collected in CAISO and delivered to PacifiCorp, according to Powerex. The congestion charges will not be returned to customers but rather spread across all of PacifiCorp’s load and exports, the paper stated.

“As a result, transmission customers that wish to use their rights to schedule physical deliveries outside of organized markets will not receive the economic value of the path they invested in, but will instead face volatile and potentially large EDAM congestion charges that they cannot manage or hedge,” Powerex argued. “Similarly, customers that wish to use their firm transmission rights in Markets+ will also not receive the economic value of the path they invested in, as they too will face these EDAM congestion charges (that are again allocated largely to PacifiCorp).”

Transmission customers will be forced to sell their transmission rights to CAISO for use in EDAM to continue receiving congestion value associated with their delivery path, Powerex contended.

PacifiCorp could lose out on $135 million per year from its sale of point-to-point service to unaffiliated transmission customers, as the proposal will reduce the incentives to invest in the company’s firm transmission service, Powerex alleges.

“Any loss of third-party transmission revenue resulting from PacifiCorp’s proposal will directly increase the revenue that PacifiCorp must recover through higher retail rates,” the paper stated. This loss in revenue has not been considered in any EDAM benefit study, according to Powerex.

Clarity Needed at Market Seam

Additionally, Powerex urged Portland General, NV Energy, Idaho Power and LADWP, among others, to “consider whether to follow PacifiCorp’s lead and jeopardize their existing transmission revenue stream, or to instead seek ways to continue to provide the core benefits that are the foundation for transmission customers’ investments in long-term firm transmission service.”

The tariff changes highlight the absence of a governance structure in EDAM that protects transmission rights “in an equitable and consistent manner,” according to the paper.

When asked to comment on Powerex’s paper, a PacifiCorp spokesperson told RTO Insider that “[i]n developing its tariff for participation in EDAM, PacifiCorp has taken the view that addressing transmission usage for other markets is premature at this stage since market to market coordination requires larger discussions with stakeholders that can only occur in the context of developed and approved market designs. Once the issues at market seams become clearer, PacifiCorp will work with stakeholders and relevant parties to address those issues.”

Portland, Ore.-based PacifiCorp, whose sprawling territory includes portions of six states, was the first utility to join CAISO’s Western Energy Imbalance Market in 2014 and the first to publicly announce its intent to join EDAM in December 2022.

The company fully committed to joining EDAM in April. (See PacifiCorp Fully Commits to CAISO’s EDAM.)

Cindy Crane, CEO of PacifiCorp, recently touted the benefits of EDAM during CAISO’s Stakeholder Symposium in October, citing CAISO data showing $6 billion in member benefits from the WEIM since its inception and $1.4 billion in benefits in a fully implemented EDAM. (See Western Utility CEOs Reflect on Evolving Energy Markets.)

However, SPP’s plan to launch Markets+ has gathered momentum over the past two years and has garnered support from powerful backers such as the Bonneville Power Administration and Powerex.

In the competition for participants between the two markets, Markets+ supporters have consistently pointed to the market’s independent governance structure and market design established under that governance. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.)

Powerex’s recent paper continued to push that argument while also claiming that EDAM benefits studies have failed to consider potential revenue losses if PacifiCorp’s transmission tariff proposal should pass.

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MISO Outlines Plan on Fast-track Queue for Resource Adequacy

MISO hopes to file a proposal in February to create an exclusive, faster route through its interconnection queue for generation projects that are key to maintaining resource adequacy.

At a special Nov. 18 workshop, Director of Resource Utilization Andy Witmeier said MISO hopes to have the fast-track process in place by June for generation projects that are key to sustaining resource adequacy over a five-year horizon. (See MISO to Devise Express Lane in Queue for Generation Projects that Keep Lights On.)

Witmeier emphasized that MISO sees the fast pass as a short-term fix, with a sunset date included in the proposal. That date would be based on the RTO’s best estimate for when it might have its interconnection process streamlined enough to achieve a one-year queue wait time for generation projects.

“It will take us time to get a one-year queue process,” Witmeier warned.

Some stakeholders said dividing the queue into two parallel processes with one given priority might result in two clogged queues, making MISO’s ultimate goal of a single, yearlong process even more unattainable.

Witmeier said MISO’s automatic withdrawal penalties in place for the traditional queue likely will curb the late-stage withdrawals that set restudies in motion and make processing sluggish.

“The restudies on the older cycles is preventing us from finalizing the newer cycles. … We’re plagued with restudies. And we can’t wait for that any longer,” Witmeier said.

“What I can tell you is, if I’m not down to a one-year queue cycle by 2028, I’m paying penalties,” he added, invoking FERC’s Order 2023.

Witmeier said that to enter the expedited process, generators must be part of a plan from a load-serving entity, be able to come online within three to five years for a known RA need, have network service to be deliverable and have endorsement by their state as a necessary project. MISO would not discriminate based on fuel type as long as a project is deemed essential.

The RTO is working with the Organization of MISO States on what documentation that states and authorities might use to demonstrate that a project is necessary, and how that documentation might differ for projects located in MISO’s deregulated areas.

Witmeier also said MISO will need to establish a cost allocation method for the projects. The RTO probably would charge a higher, nonrefundable application fee to cover staff hours for the studies, which will be conducted serial-style instead of in batches.

Clean Grid Alliance’s Beth Soholt asked what would happen if a project enters the expedited queue only to not ultimately receive a certificate of public convenience and necessity.

“Ultimately, whether or not to recognize that project is necessary as a resource adequacy project is up to that jurisdiction,” MISO Deputy General Counsel Kristina Tridico said.

“We think the likelihood of projects going into [the expedited queue] and dropping out is very low,” Witmeier added. Projects that have state backing are already usually considered foregone conclusions, he said.

Travis Stewart, representing the Coalition of Midwest Power Producers, said that even an express lane will not make RA projects “immune” from the exorbitant network upgrade costs often found in MISO interconnection studies.

But Witmeier said that under the expedited processing, developers should get a clearer idea sooner of network upgrade costs.

“We expect a lot of these LSEs will have done their due diligence and done their own studies on expected network upgrades,” he added.

So far, MISO is not proposing a withdrawal penalty for the expedited class of projects. Stakeholders asked it to reconsider that stance, arguing that even those projects could be canceled.

Sustainable FERC Project’s Natalie McIntire said existing projects in the regular queue might be harmed financially through expedited projects snapping up available transmission capacity first. She asked how MISO would make sure that the regular queue is still viable.

Witmeier said MISO will draw on the same system modeling for the regular and accelerated processes. He said projects in both queues would have a chance to claim transmission capacity on the system. After that, MISO would consider it unavailable.

McIntire said she did not see how, somewhere along the line, the parallel processes would not assign the same transmission spot to two projects.

“It seems to me we have a math problem,” McIntire said.

“It seems like an age-old problem that we’ve had, and we’re compounding it,” WEC Energy Group’s Chris Plante agreed.

MISO will hold another workshop to hammer out details on its expedited resource adequacy queue studies Dec. 6.