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November 24, 2024

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SPP Sees Bias in Brattle Western Market Studies, Exec Says

An SPP executive closely involved with developing Markets+ said recent Brattle Group studies on Western day-ahead markets appear to be aimed more at swaying utilities in favor of CAISO’s Extended Day-Ahead Market than providing an unbiased assessment of the two offerings.

“We’ve observed a lot of statements and assertions — and even studies — that really seem more like attempts to pressure Western entities into a market selection rather than work directly with those Western entities to truly understand what their issues and concerns are, and also work to try and accommodate them and address those issues so they want to choose to be within that market,” SPP Vice President of Markets Antoine Lucas said during an interview.

Brattle’s John Tsoukalis, the lead author on the studies, objected to that depiction of his group’s work, saying the company’s clients “are looking for solid analytical support for their decision making, not a biased analysis or advocacy.”

RTO Insider spoke with Lucas and SPP Senior Director of Seams and Western Services Carrie Simpson on Oct. 16 to discuss Brattle’s Oct. 1 comparative white paper on Markets+ and EDAM, which Lucas said “misrepresented” aspects of SPP’s day-ahead platform. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)

That study, which compared seven key features of the two markets — such as transmission optimization, fast-start pricing and seams management — offered a more favorable assessment of the CAISO market but stopped short of endorsing it.

Vancouver, British Columbia-based Powerex, the first entity to tentatively commit to Markets+ two years ago, quickly published a rebuttal to the study, with SPP following up with its own set of “corrections” shortly after. (See Powerex Contests Brattle’s EDAM/Markets+ Comparative Study.)

Lucas said SPP has tried to stay outside the fray of Western market debates but felt compelled to respond directly to the comparative study because “there were certain things or statements” made about Markets+ “where we felt it necessary and appropriate to address and try to clarify with facts. And then there were other areas where we just felt like there was either a lack of information or characterization of certain things that misrepresented the product.”

The SPP response criticizes the Brattle study in four areas, including its conclusions around “look ahead” unit commitment design, fast-start pricing, greenhouse gas accounting design and congestion rent allocation.

Regarding the first subject, SPP faults the study for conflating the real-time unit commitment design used in RTO’s Western Energy Imbalance Service with the different one to be implemented in Markets+. On the GHG issue, SPP contends the study overlooks the full set of methods Markets+ uses to reduce “leakage” when accounting for emissions from generating resources.

On the last subject, SPP contends Brattle “grossly oversimplifies the complex policy considerations behind fair congestion revenue allocation” by concluding the two markets’ differing models will yield similar results.

Lucas said SPP finds Brattle’s conclusions “concerning” because third-party studies are “typically intended to bring trust to the process.”

“We wanted to make sure that people were aware of the mischaracterizations of Markets+ and also recognize that in every one of those cases, those errors and mischaracterizations tended to depress the anticipated value proposition for Markets+,” he said. “We know that a lot of people are looking at these studies and then using them in different ways to inform themselves around either decisions that they’re going to make or positions that they’re going to take on the markets.”

‘Equitable Distribution’

Lucas said SPP was not yet prepared to comment on a more recent Brattle study zeroing in on benefits for the Bonneville Power Administration (another Markets+ supporter) and the Pacific Northwest at large.

That study, which focused on adjusted production costs (APC), found BPA could earn an estimated $65 million in annual benefits from joining EDAM while facing increased yearly costs of $83 million in Markets+. Similarly, the Northwest could reap $430 million from widespread participation in EDAM but might see net revenues decline by $18 million in Markets+, according to the study. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

Lucas questioned why Brattle produced a study trying to estimate BPA’s benefits “rather than BPA themselves being able to conduct those assessments and if those [benefits] provide what they see as value to them and their customers.”

Asked whether Western utilities’ day-ahead market decisions should come down to estimates of economic benefits based on APC or other factors, Lucas said the discussion should extend beyond the notion of calculating “regional benefits” to considering how those benefits are distributed.

“What we constantly wrestle with in policy development is we’re finding policies that benefit the overall region, but also do it in a manner where there is equitable distribution of value among the participants who are bringing the assets into that market,” he said, adding that APC estimates, while important, are just one component of overall market benefits.

Lucas responded with good humor to a hypothetical question about whether Markets+ could ensure an equitable distribution of benefits in a footprint that included California and the CAISO area or if, as some Markets+ supporters believe, participants would do better to negotiate with the larger entity from behind a market seam.

“Under a scenario where California was part of Markets+, they would be another [balancing authority], just like the other BAs. They would be a very large BA, and from our standpoint as SPP, our approach to facilitation doesn’t change. You just have another BA who’s participating in that stakeholder process that’s advocating for the things that they believe are best for them and their consumers,” he said.

Simpson said the “independent, inclusive” Markets+ governance framework is designed to accommodate a BA the size of CAISO.

“I think the design, the actual market design, in addition to the governance, would support that equity that we’re talking about. So that hypothetical, I think, would work,” Simpson said.

“And in the alternative, then you have market operators representing their respective customers’ interests at the seam on a peer-to-peer basis, and so that is also really helpful, too, if you’re an entity in Markets+, in having that representation by your market operator to look out for the interests of that market,” she said.

No ‘Preconceived Notions’

Reached for comment, Tsoukalis said Brattle “appreciates all responses” to its Western markets work and is “always open to input on our analyses, assumptions, and our understanding of the market options.”

“We do not engage in advocacy work and do not take on work on preconceived notions of what our results will look like. Rather, we strive to do unbiased, high-quality work to support well-informed decision making by our clients, who in this case are Western utilities, cooperatives and public power entities,” Tsoukalis said in an email.

Tsoukalis said he wanted to ensure other “key points” aren’t lost in the Western debate, including the fact that both Markets+ and EDAM represent an improvement over the status quo; that most “market-related benefits to specific entities will be driven by the transmission capabilities, and diversity of loads and generation resources of market participants;” and that Brattle recognizes that estimated cost savings in either market are not the only — or even most important — factor affecting market participation decisions.

He noted that Brattle has found that each market includes design elements that are “more attractive” than the other market.

“The availability of (and competition between) two market options has benefited the development of both EDAM and Markets+ as both markets have worked harder to offer an attractive and efficient market design.  The benefit of this competition is expected to continue as both markets evolve over time,” Tsoukalis said.

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Utilities and Grid Operators Urge Caution on DLRs, State Regulators and Consumers Want Action

FERC got more than 60 comments on its advanced notice of proposed rulemaking (ANOPR) on dynamic line ratings (DLRs), with utilities and grid operators urging caution on new requirements while state regulators, consumers and grid-enhancing technologies (GETs) firms want mandates. (See related story: FERC Gets Mixed Advice on How Quickly to Move on DLR Requirements.) 

The ANOPR proposes requiring transmission providers to reflect the impacts of solar heating on transmission line ratings, reflect forecasts of wind on certain lines, ensure transparency in the development and implementation of DLRs and enhance data-reporting practices in non-RTO regions to identify candidate lines to reflect wind conditions. 

PPL is an investor-owned utility with subsidiaries in the Eastern Interconnection that have been testing DLRs. It said they promote operational performance and save customers money. 

“By measuring wind, sag and conductor temperature directly, a machine-learning tool can fine-tune the external forecasts for each transmission facility,” PPL said. “When these forecasts are accurately incorporated into day-ahead models, RTOs like PJM can dispatch lowest-cost generation where it might otherwise be blocked by transmission line congestion.”  

But the ANOPR needs to better consider where DLR implementation would be most effective. PPL argued that FERC should reconsider mandating that transmission owners calculate and apply ratings using a specific methodology. 

“Doing so would upend the risk tolerances built into the utilities’ existing ratings methodologies and limit their ability to allocate acceptable risks throughout their systems,” PPL said. 

The fundamental question for line ratings is how much thermal energy to allow, which has never been dictated by regulators and always left to transmission owners, informed by good utility practice. 

“FERC taking more control of the factors being used in ratings calculations means that regulators in Washington, D.C., not the owners of the assets who are responsible for their reliability, safety and longevity, are the ones deciding on how much risk is acceptable,” PPL said. “FERC does not have, and can never have, all the relevant information needed to make these decisions.” 

Dominion Energy is working with the U.S. Department of Energy to test out DLRs around “data center alley” in Loudoun County, Va., which is home to the largest concentration of the facilities in the world and is a major factor in the load growth in PJM. The utility argued that the technology makes more sense for short-term operational efficiencies or for contingencies. 

“Short-term DLR benefits are not a substitute for the transmission planning necessary to ensure long-term reliability,” Dominion said.

The New York Transmission Owners also voiced some support for GETs in general, but do not want FERC to move ahead with DLR requirements now. 

“Rather than ordering prescriptive DLR requirements, the commission should continue to promote and explore DLR technologies and allow regional flexibility for TSPs and TOs to develop targeted DLR programs that make sense for their respective systems,” they said. “For example, much of the Consolidated Edison transmission network is underground, and DLR implementation clearly should not be required for transmission lines that are not exposed to sun or wind.” 

The issues in New York go beyond underground lines in Manhattan, with the NYTOs telling FERC that much of their system is getting old and it would make more sense to replace aging infrastructure rather than try to squeeze a few more efficiencies out of it. 

ISO/RTOs also Preach Caution

PJM told FERC it supports DLRs in high congestion areas as a real-time optimization tool. But it said FERC should let the benefits of Order 881 that mandated that the related Ambient-Adjusted Ratings (AARs) in ISO/RTOs be better understood before moving onto DLRs. Order 881’s requirements for AARs go into effect in July 2025 and will have line ratings take temperature into account, which has some overlap with DLR benefits. 

PJM supports delaying DLR implementation until after Order No. 881 requirements provide the data “needed to identify changed transmission line congestion patterns,” the RTO said. “The potential benefits of DLR cannot be reliably estimated before implementation of Order No. 881.” 

Projecting the cost-benefit ratio of using an ANOPR-adjusted rating on a congested facility as compared to a seasonal rating “may grossly inflate the benefits if not adjusted for the efficiencies gained using an Order 881 AAR,” it added. 

MISO supports using DLRs as another tool to help reliably deal with the changes its system is going through, but it argued they do not make sense everywhere. It also highlighted overlap with Order 881. 

“DLRs, when selectively deployed, can support the efficient use of existing transmission infrastructure,” MISO said. “But they are not a long-term solution to meet emerging system needs. Like AARs, DLRs can provide operational benefits but cannot solve significant long-range transmission problems. Development of additional transmission investment will be critical to meeting the challenges of grid transformation.” 

CAISO said DLRs make sense where they materially enhance the reliability and efficiency of transmission operations. “Requiring the blanket use of dynamic line ratings — even through a phased implementation and subject to an exception process as set forth in the ANOPR — may not advance reliability and efficiency in all cases,” CAISO said. 

State Regulators and Consumer Groups Support ANOPR

The Organization of MISO States said the reforms in the ANOPR are needed to ensure reasonable rates and the use of DLRs will increase efficiency and reliability while cutting costs to consumers. 

“The ANOPR proposes additional requirements beyond Order No. 881 that require line ratings that account for solar heating, wind speed and wind direction,” OMS said. “Without taking these conditions into consideration, transmission owners are likely not fully utilizing the available capacity on transmission lines.” 

The proposal builds on five years of work looking into GETs with AARs expected to save up to 15% of total congestion in MISO. While many of the benefits come from pushing more energy through lines, OMS noted that DLRs can lower them with a study out of Massachusetts showing that effect 22 to 27% of the time. 

“This lowering of transmission line ratings also suggests that DLRs have additional long-term benefits because overrating a transmission line can lead to safety risks and premature degradation of a transmission line,” OMS said. 

The Organization of PJM States (OPSI) supports the reasonable implementation of DLRs, which is in line with its mission of ensuring reliable service at affordable rates. But the group did caution FERC against being overly prescriptive and ensuring DLRs can be implemented strategically. 

Utilities have been too slow in taking up the technology, which OPSI said requires some regulatory mandates. In PJM’s case, OPSI said the issue was with a lack of competition in the transmission planning process, which in the 2022 Regional Transmission Expansion Plan Window 3 procured $5 billion worth of new lines with zero DLRs. 

“PJM itself has made the case that the sponsorship model is insufficiently competitive,” OPSI said. “In its comments in the ANOPR that eventually became Order No. 1920, PJM noted that only three total project selections were awarded to non-incumbent developers out of 185 total project awards. According to PJM, the reason for this mainly comes down to the availability of existing right-of-way for incumbent developers, which is a major cost and constructability advantage.” 

The R Street Institute supports the ANOPR and pinned utilities’ lack of movement on the technology on a more basic issue. 

“DLRs have been and will continue to be chronically underutilized because of [transmission providers’] perverse incentives under cost-of-service regulation,” R Street said. “This inhibits market trading by inflating congestion costs unnecessarily. Thus, the status quo is unjust and unreasonable.” 

FERC should require DLR with a rebuttable presumption of prudence, unless transmission providers can show they fail a cost-benefit test.  

R Street also argued that FERC needs to start getting more information from non-RTO regions and it should not fail to require DLRs inside organized markets out of a fear of making a disincentive for new participation. DLRs would only enhance the net benefits of RTO participation, R Street said. 

“The determinates of RTO expansion hinge on many factors that tilt in favor of DLR adoption to enrich RTO value proposition, as the perceived net benefits are strong considerations in state RTO expansion conservations, such as those underway in the West,” R Street said. 

The Electricity Consumers Resource Council (ELCON), Clean Energy Buyers Association and Electricity Consumers Alliance represent large customers, and they all want to see DLR requirements move forward. 

“Given the potential economic and reliability benefits of implementing grid enhancing technologies, such as DLR, large consumers urge the commission to expeditiously incorporate the information gathered in this ANOPR into a formal proposal that supports adoption of all beneficial grid enhancing technologies rather than individual technology-specific solutions on a case-by-case basis,” they told FERC. 

GETs Firms Support the Rule Change but Have Suggestions

LineVision argued that the wind ratings proposed in the rule, which FERC would require on some congested lines as opposed to the more universal solar radiance requirements, are the more important of the two. If anything, having one standard with wind and solar radiance rolled into one would make sense. 

“More accurate line ratings that reflect the impact of wind on a transmission line will result in increased line ratings a vast majority of the time, which will relieve congestion and quickly result in more affordable rates for customers,” LineVision said. “Without sensor-based DLR, transmission owners will continue to rate their lines based on simplistic assumptions that do not represent the real-time or [forecast] capacity that lines can deliver.” 

Even when DLRs do not significantly affect congestion, they still can improve overall system efficiency. 

“In those instances where DLR may not relieve congestion, it will still result in more just and reasonable rates because asset life will not be shortened due to running a line at its overstated capacity,” LineVision said. “The need for DLR is critical in avoiding the scenario that occurred in 2003, when a conductor sagged beyond its limits and touched vegetation, causing the Northeast blackout, which caused outages for approximately 55 million customers.” 

Addressing transmission line ratings “was one of the recommendations made by the U.S.-Canada Power System Outage Task Force in its review of the blackout. In the long run, a grid operated according to accurate ratings will be more affordable for all,” LineVision said. 

An open question is whether the wind speed DLRs will even require sensors, noted the Southwest Power Pool’s Market Monitoring Unit. The technology is new, so FERC should allow for some more testing of alternatives. 

“A phased-in timeline will allow transmission providers to explore the least-cost options for wind requirement implementation, identify lines where costs might outweigh the benefits and potentially allow new, lower cost technology to enter the market,” the MMU said. “The commission should solicit comments from transmission providers on what an appropriate phase-in timeline for 100% implementation of the wind requirement would be.” 

GE Vernova Electrification Software said its software can avoid the need for sensors, the cost of which has been a hurdle to DLR deployment. The software also can be used on substations, which often are the limiting element on a line, not just the overhead line conductors. 

Software solutions also can work alongside sensors to develop a hybrid approach that maximizes DLR effectiveness. 

“Such hybrid solutions can be provided by a single vendor with capability in the hardware and software realm, through partnerships between vendors or, more generically, via appropriate data integration projects of separate vendor solutions at a customer site,” GE Vernova said. 

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FERC Accepts SPP’s PRM Compliance Filing

FERC has accepted a second compliance filing from SPP outlining its process for determining its planning reserve margin (PRM) with an Oct. 17 order that found the RTO’s response met the commission’s directives, effective April 10, 2024 (ER24-1221).

SPP was responding to FERC’s May order asking for more information on how it uses loss-of-load expectation (LOLE) studies to determine the PRM. (See FERC to SPP: Show More Work on PRM Determination.)

FERC directed SPP to revise its tariff to include more information related to a “non-exhaustive” list of the factors SPP staff, its board and its state regulators will consider when determining the recommended PRM value.

The commission disagreed with protests filed by several SPP members (American Electric Power, Golden Spread Electric Cooperative, Arkansas Electric Cooperative Corp., Xcel Energy, East Texas Electric Cooperative and Northeast Texas Electric Cooperative) that the grid operator did not explain how it will use the LOLE results to determine the PRM. FERC said the proposed tariff language “makes clear” that the PRM value will be determined based on the LOLE study results and that SPP set forth factors that its staff, board of directors and state regulators will consider when using the study results.

SPP’s Market Monitoring Unit also protested, arguing that the tariff shouldn’t reference available generating capacity and new generator development timelines as considerations for recommending or determining the PRM. FERC disagreed, noting that it already accepted a similar provision in the first compliance order.

“That’s a win, I guess, depending on who you ask,” SPP attorney Justin Hinton said to chuckles during a stakeholder meeting Oct. 18, referencing the stakeholder arguments that preceded the PRM’s revision in 2022.

The board approved changing the PRM to 15% from 12% over opposition from stakeholders advocating a three-year phase-in. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

Commission OKs LTCR Change

In an Oct. 11 letter order, FERC also accepted SPP tariff revisions to allow the nomination of candidate long-term congestion rights (LTCRs) for firm transmission capacity associated with the Federal Service Exemption (FSE) and for firm transmission service associated with grandfathered agreement (GFA) carve outs in the LTCR allocation process (ER24-2003).

FERC said the revisions, effective July 14, 2024, are likely to benefit load by further reducing uplift charges that load currently pays to compensate for the congestion and marginal loss charges that GFA carve outs and FSEs do not pay.

SPP said congestion charges associated with the carve outs and FSE transmission reservations have been offset by revenues that SPP receives from nominating auction revenue rights (ARRs) attributable to the carve outs and FSEs. The remaining amount is recovered from SPP-wide load as uplift.

The RTO said it will nominate LTCRs attributable to the carve outs and FSEs under the same criteria by which it currently nominates ARRs attributable to the same exemptions. It said the LTCRs’ revenue will be used to further offset the uplift charges that must be paid by load.

FERC rejected Missouri River Energy Services’ protests that the revisions shift costs to market participants with transmission reservations near the carve out and FSE reservations. It said the alleged cost shifts result from better aligning the tariff’s treatment of ARRs and LTCRs attributable to carve outs and FSEs with the tariff’s treatment of ARRs and LTCRs attributable to all other transmission reservations.

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MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects

CARMEL, Ind. — MISO announced it will move forward on an annual interconnection queue cap based on 50% of peak load for the year in question, this time removing exemptions for projects regulators deem essential.  

Stakeholders learned at an Oct. 16 Planning Advisory Committee meeting that MISO plans to scrap a regulator exemption from the annual megawatt cap it has designed for its generator interconnection queue. The deletion appeared unpopular among some stakeholders and state regulatory agencies.  

MISO’s Ryan Westphal said removal of regulators’ ability to name exempted generation projects will prevent the cap from being diluted with exceptions to the rule. He also said MISO heard stakeholders’ concerns about how MISO would limit the number of regulators’ exemptions and how it would give those exemptions priority.  

FERC last year rejected MISO’s first attempt to institute an annual megawatt cap on the queue based on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)   

Westphal said MISO needs a “reasonable number of resources and a reasonable dispatch” to be able to build sound study models.  

“All of us can agree that in the 2022, 2023 modeling, there are a lot of resources in there that are creating a lot of difficulties, engineering problems,” Westphal said.  

Westphal also said a 50% peak load cap should eliminate the need for “backbone” network upgrades, where interconnection customers are responsible for large transmission projects.  

MISO previously said regulatory authorities would be allowed exemptions to the cap when generation additions are needed for resource adequacy or to serve documented load that regulators have authority over. MISO said it would allow one cap exemption per 3 GW of documented load that the regulatory authority serves. (See MISO: 50% Peak Load Cap, Software Help Key for Crowded, Delayed Queue.) 

MISO has said that even with a cap in place, it could achieve a total 310-GW queue throughput through 2042. The RTO assumed a 68-GW annual cap based on its current annual peak and took its historic 21% completion rate into account to come up with 14.3 GW per year in completed projects. MISO has about 320 GW in active interconnection requests in its queue. 

MISO staff have said controlling the cadence of project submissions is key to improving the quality of initial studies and potentially reducing network upgrade costs by being able to use a more true-to-life resource dispatch in models. MISO said once a cap is met for an interconnection cycle, projects will line up for the next year’s study cycle.  

The RTO has also committed to a three-year review of the effectiveness of the queue cap. 

MISO: 2nd Filing on the Way to Address Regulators’ Necessities

MISO’s Andy Witmeier said MISO dropped regulators’ exemption because planners didn’t see how a single exemption could address the multitude of imminent resource adequacy troubles.  

Instead, Witmeier said MISO will develop a separate, “more holistic” proposal with stakeholders to find ways to speed up queue processing for projects that keep MISO in the black on resource needs.  

Duke Energy’s Jay Rasmussen said he thought MISO is missing an opportunity to address resource adequacy issues within the cap.

Rasmussen pointed out that large load additions are on the horizon for load-serving entities. He said filing to implement a cap without acknowledging generation needs creates a “lag” for interconnection customers. 

Illinois Commerce Commissioner Michael Carrigan said while the Organization of MISO States sympathizes with how difficult queue studies have become for MISO, “states very clearly value their respective authority.” Carrigan said he didn’t see a path to states supporting MISO’s queue cap proposal at FERC without some sort of exception for generation needed to preserve resource adequacy. 

“This is a concern and could be very problematic,” Carrigan said.  

“Our decision is that we need to address these in separate filings because they’re separate issues,” Witmeier said. He said MISO staff plan to discuss how to expedite generation projects necessary to resource adequacy in upcoming Planning Advisory Committee meetings through January. He said MISO could be ready for a separate filing by the first quarter of 2025.  

MISO’s Andy Witmeier | © RTO Insider LLC 

At a Sept. 12 Organization of MISO States board meeting, OMS Director of Legal and Regulatory Affairs Brad Pope said MISO’s queue cap needs a “workable” exemption for regulatory agencies when they are reliant on a developer’s generation submittal. 

While it’s jettisoning its regulator exemption, MISO said it would maintain cap exemptions for existing resources. Those resources may need to enter the queue to replace their output with an approved generation facility, receive provisional interconnection agreements or upgrade their current basic, unguaranteed energy resource interconnection service to the higher-quality, firm network resource interconnection service. Staff said those reasons don’t include proposing speculative generation projects and can earn exemptions.  

Bill Booth, consultant to the Mississippi Public Service Commission, argued that projects regulators approve under utilities’ integrated resource plans are not speculative.  

“The goal of this whole approach is to reduce speculative projects. Do you think projects approved under a state IRP process are speculative?” he asked rhetorically.  

Witmeier said the past few times MISO discussed its proposed cap with stakeholders, the regulator exemption proved to be a sticking point.  

“Folks are concerned about what it means and how it will be managed,” he said.  

Some stakeholders asked MISO to delay its planned early November filing with FERC for a queue cap until it devises a way to address projects deemed necessary by states for resource adequacy.  

NextEra Energy’s Erin Murphy said a “brief pause” makes sense considering MISO is working with tech startup Pearl Street to automate some study processes. She said perhaps MISO could wait to gauge the effectiveness of the new software’s ability to shrink wait times before it limits entrants.  

Witmeier, however, said a queue cap has been in the works in MISO’s stakeholder process for two years. He said the need for a queue cap and creating a means to usher resource adequacy projects through faster are unrelated matters.  

“I see no need to put it on the shelf just because we’re going to go after a separate process,” Witmeier said.  

Booth said MISO required a little “intellectual integrity.” He said instead of MISO polishing and explaining a regulator exemption, MISO simply chopped its filing in half, with no guarantee of when it would address state-required generation projects.  

Consumers Energy’s Dan Alfred said his utility’s support of the queue cap hinges on a companion resource adequacy exemption.  

“I don’t understand why you’re not listening to the feedback here,” Alfred said. 

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FERC Reverses Decision on WestConnect Cost Allocation

Responding to an appellate court’s concerns about free ridership, FERC reversed a decision that allowed the WestConnect transmission planning region to include a category of participants not subject to binding cost allocation. 

The order (ER13-75, et al.), issued Oct. 17, could mark the end of a yearslong dispute stemming from FERC Order 1000. 

That order, issued in 2011, requires public utility transmission providers subject to FERC jurisdiction to participate in a regional transmission planning process that produces a regional transmission plan. 

Nonpublic utility transmission providers may also choose to participate in regional transmission planning by “enrolling” in the effort. They are then required to pay a share of costs for future projects that benefit them.  

And in what has become a contentious twist, a FERC-approved framework for WestConnect allows a third category of participants: coordinating transmission owners (CTOs). These nonpublic utility transmission providers participate in determining regional transmission needs and identifying projects that could meet those needs. But once costs of a proposed project are divided up, the CTOs choose whether they want to pay. 

If a CTO decides not to pay, WestConnect reevaluates the costs and benefits of the project to determine if it should move forward.  

In an August 2023 decision, the 5th Circuit Court of Appeals said FERC’s approval of the framework was “incompatible with the FPA’s [Federal Power Act’s] mandate for just and reasonable rates and with Order No. 1000’s application of the cost causation principle.” 

A stated purpose of Order 1000 is to prevent subsidization by ensuring that costs correspond to benefits, the court decision stated, and the cost-causation principle combats “free ridership,” in which an entity is not required to pay for a benefit it receives. 

FERC has now directed WestConnect public utility transmission providers to submit compliance filings to revise their Open Access Transmission Tariffs to remove the CTO framework and to update their OATTs to reflect the current list of enrolled members in the WestConnect region. 

Long-running Case

After FERC issued Order 1000, the WestConnect public utility transmission providers submitted a series of filings beginning in 2012 to comply with the order’s requirements. WestConnect covers parts of Arizona, California, Colorado, Nebraska, Nevada, New Mexico, South Dakota, Texas and Wyoming. 

FERC rejected several of the WestConnect public utility transmission providers’ cost allocation proposals, saying they weren’t consistent with the order’s principles. But FERC accepted the providers’ proposed participation framework in which nonpublic utility transmission providers could participate as either enrolled transmission owners or coordinating transmission owners. 

The public utility transmission providers, led by El Paso Electric, took FERC’s rejection of their filings to court.  

The 5th Circuit vacated FERC’s orders regarding the transmission providers’ compliance filings and remanded the case “for further explanation and fact finding.” 

In 2017, FERC responded with an order on remand. Among the commission’s arguments in support of its decision was that nonpublic utility transmission providers are likely to submit to binding cost allocation so grid-improvement projects meet benefit-to-cost thresholds and can move forward. 

FERC also said it could always revisit its approach if free ridership turns out to be more of an issue than expected.  

The public utility transmission providers asked for a rehearing, which FERC denied. El Paso Electric then took the matter back to the 5th Circuit, petitioning for review of FERC’s order on remand and order denying rehearing.  

The other WestConnect public utility transmission providers intervened in support of El Paso Electric, and the nonpublic utilities intervened in support of FERC. 

The court stayed the petition in 2018 while the parties worked on a settlement agreement. But in 2022, FERC rejected the proposed agreement between the public and nonpublic utilities and the court continued with its review of the case. (See WestConnect Tx Cost Allocation Plan Rejected by FERC.) 

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MISO Dubious of Opt-out Request for DER Affected System Studies

CARMEL, Ind. — MISO is hesitant to grant a request from Michigan to give dispensations to distributed energy resources from its mandated affected studies that gauge transmission system impacts.

Michigan regulators and utilities’ recent bid to allow DERs to altogether skip out on MISO’s affected system-style studies might be shortsighted, said MISO Senior Manager of Resource Utilization Kyle Trotter.

“Generally, we are supportive of this particular issue; however, we’re not quite sold on an exemption from the whole process,” Trotter said during an Oct. 16 Planning Advisory Committee meeting.

Trotter emphasized the need for appropriate reliability assessments for DER additions. He said MISO cannot ignore DERs’ potential to affect local transmission systems and neighboring systems. Trotter said MISO needs some “touchpoint in place” to maintain visibility of DERs, continue to meet NERC reliability standards and have an idea of which interconnection points on the system are congested for its interconnection queue.

“We need to see what’s happening at those transmission-distribution interface. We need to keep visibility into what’s happening whether those DERs go through the MISO study process or not,” Trotter said.

Trotter also said MISO’s upcoming compliance with FERC Order 2222, which will allow aggregated DERs into the MISO markets, presents another reason to keep tabs on DERs.

“We would like to know about these before they show up and register for the market,” Trotter said.

Last year, MISO decided it would evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. TOs screen for the 5 MW injection capability, while the RTO ascertains whether the DERs could influence a 1% line-loading change.

If the DER is shown to impact both reliability criteria, MISO issues a report that triggers its existing facilities study and could lead to network upgrades. TOs pay a $60,000 study deposit to MISO per substation that is required to be studied for DER impacts. MISO refunds any portion it doesn’t use for the studies. (See MISO Creating Means to Gauge Impacts of DER Interconnections.)

In July, Michigan utilities and the Michigan Public Service Commission asked MISO to rethink a study requirement for DERs that might influence the grid. They said MISO’s study process is burdensome, costly and limits efforts to integrate DERs on the grid. (See Michigan Utilities Call for Opt-Out on MISO DER Affected System Studies.)

Some stakeholders said MISO’s DER-affected system studies are redundant considering that MISO’s transmission owners already study DERs’ influence under transmission expansion planning and that MISO is devising a registration process for DERs that want to participate in markets.

ITC’s Ruth Kloecker agreed that MISO’s study process seems duplicative. She also said MISO’s 5 MW threshold seems too severe.

“5 MW of injection? I don’t know how that can seriously impact the transmission system,” Kloecker said.

Erik Hanser, a staffer with the Michigan Public Service Commission, asked if MISO sees a way to cut back study requirements on DERs.

Trotter said MISO would like to continue DER awareness and likely would maintain MISO’s policy of having TOs vet DER additions and notify MISO if an impact study is warranted. He said there’s a possibility DER additions could skip a “full MISO study and associated costs in some instances.”

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New IIJA Funding Targets Grid Resilience and Demand Growth

With downed power lines and poles from hurricanes Helene and Milton still a painful memory for many, the U.S. Department of Energy on Oct. 18 announced almost $2 billion in new funding from the Infrastructure Investment and Jobs Act aimed at improving grid reliability and resilience. 

The latest round of Grid Resilience and Innovation Partnerships (GRIP) awards will go to 38 projects across 42 states and the District of Columbia. The grants will be used to expand grid capacity and speed up interconnection to meet burgeoning power demand from new manufacturing and data centers, said Secretary Jennifer Granholm during an advance press call Oct. 17. 

“The funding couldn’t come at a more critical time,” Granholm said. “Energy demand, as we know, is rising nationwide, and it is straining our outdated grid infrastructure, and as climate change worsens, we’re seeing more frequent and devastating storms like Helene and Milton.” 

The projects selected for the GRIP awards will expand capacity on regional grids by 7.5 GW and add 300 miles of new lines and upgrade an additional 650 miles of lines with advanced conductors and other grid-enhancing technologies (GETs), according to a DOE press release.  

President Joe Biden announced six of the projects ― all located in the Southeast ― during a visit to Florida on Oct. 13. The Tennessee Valley Authority (TVA) scored the largest award, $250 million, which will fund 84 “subprojects” in disadvantaged communities across eight states, adding more than 2,400 MW of capacity, according to a DOE fact sheet. 

The federal dollars also will be used for the first interconnection tie — cables — allowing for power transfers between TVA and the Southwest Power Pool, providing TVA and its local utilities with an additional 800 MW of electricity.  

In Florida, Gainesville Regional Utilities (GRU) is slated to receive $47.5 million for distribution grid upgrades including reconductoring, undergrounding and transformers. DOE’s project description notes that this “diverse portfolio of grid hardening and modernizing technologies and equipment will increase the grid’s intelligence and build system capacity for the adoption of clean energy, grid-edge technologies and electric vehicles.” 

GRU CEO Ed Bielarski said he wants the utility to be a model “to further innovate and enhance [system] resilience and storm response, including in disadvantaged communities.”  

The new projects are part of the second round of GRIP awards, following an Aug. 6 announcement of eight projects across 18 states receiving $2.2 billion. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)  

The GRIP program includes three separate funding streams: the Grid Innovation grants, announced in August, and the just-announced Grid Resilience Utility and Industry grants and Smart Grid grants. Pending the election results, DOE is planning a third round of funding for 2025. 

Speaking at the advance press call, John Podesta, Biden’s senior adviser on international climate policy, said the U.S. needs the grid to be “larger, stronger and more reliable. To effectively tackle the climate crisis and stay on course to reach 100% clean energy by 2035, we need to double our current transmission capacity in that time frame.” 

Getting there will mean continued public and private investments, better interregional transmission planning and “cutting through red tape” to get projects sited, permitted and built, Podesta said.  

Project Priorities

The IIJA provided $10.5 billion for the GRIP program, heralded as one of the largest public investments in the nation’s electric infrastructure. With the Oct. 18 announcement, $7.6 billion has been awarded.  

In general, awardees must at least match the number of federal dollars, and with the current announcement, DOE said the almost $2 billion in GRIP awards would draw in an additional $2.2 billion in private investment.  

Announced exactly one year ago, on Oct. 18, 2023, the first round of awards, totaling $3.46 billion, included 58 projects in 44 states. According to a senior administration official, 53 of those projects now have signed contracts with DOE. The projects announced in August are in contract negotiations, which also will begin for the latest round of awardees. 

DOE officials have said repeatedly that once an awardee has a signed contract, the funds will be committed and safe from any claw-back, regardless of the outcome of the election. 

Each round of GRIP awards has focused on different administration priorities. The first round leaned heavily toward projects that could improve resilience at the distribution level, had strong support from state and community officials and could move forward quickly. 

The largest award in the first round ― $464 million ― went to the five transmission lines in MISO and SPP’s joint targeted interconnection queue (JTIQ) portfolio. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)  

Transmission projects were the top priority for the awards announced in August, with projects deploying GETs securing six of the eight awards. The largest award, $700 million, went to the North Plains Connector transmission project, a 420-mile, high-voltage direct current line running from Montana to North Dakota. 

This round clearly prioritizes grid upgrades to improve resilience in areas especially vulnerable to extreme weather and to get more power online to meet rising demand. The projects are geographically diverse, with money going to red and blue states. Investor-owned utilities, municipals and electric cooperatives are on the list, as well as some technology companies. 

In North Dakota, the Montana-Dakota Utilities Co. and Innovative Energy Alliance Cooperative were awarded close to $15.6 million for a project to upgrade a 54-mile segment of the state’s grid, adding new advanced conductors to expand capacity. Other upgrades include “installing software, sensors and interfaces for online weather data, allowing for dynamic line rating and quicker system response,” according to DOE. 

Alabama’s Tombigbee Electric Cooperative, with about 45,000 members, is slated to receive $11.1 million for system upgrades including new storage to shave peak demand and distributed energy management and outage management systems. The project also will reconductor existing lines and install new lines.  

In Florida, Chicago-based Switched Source will partner with Florida Power & Light to deploy its automated distribution power flow control technology on lines in disadvantaged communities especially vulnerable to extreme weather. The $47.7 million award could help cut outages by 10%, improve energy efficiency across the system and help integrate distributed resources, such as solar and electric vehicles.  

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SPP Stakeholders Endorse Record $7.65B Tx Plan

LITTLE ROCK, Ark. — SPP stakeholders on Oct. 15 approved what one member called an “historic” transmission plan that will eclipse any previous portfolio by a factor of five.

The grid operator’s 2024 Integrated Transmission Plan’s portfolio includes 89 projects, including more than 1,900 miles of rebuilt or new EHV transmission, with a projected cost of $7.65 billion. That’s more than half the $12 billion of transmission facilities that SPP has directed, members have built or are building.

The ITP assessment cleared the Markets & Operations Policy Committee with 95% approval. It will go before SPP’s Board of Directors on Oct. 29 with passage almost guaranteed, considering stakeholders’ approval margin.

“This is a monumental day in SPP history,” Sunny Raheem, the RTO’s director of system planning, said at the MOPC. “That brings into question, is it affordable?”

Staff said their study of the plan’s two futures found benefit-to-cost ratios over 40 years of 8.9 and 8.2, about three points higher than any previous ITP assessment. They also expect the 2024 portfolio to be fully paid back within its first three years.

Natalie McIntire, speaking for the Natural Resources Defense Council, offered her “strong support for this historic ITP.”

“We think [it’s] really needed to allow SPP to maintain a reliable system, be prepared for the changing resource mix, and, of course, load growth,” she said. “We were amazed and pleasantly surprised at the very strong levels of benefits relative to cost in this portfolio, and I think that that should make everyone feel fairly comfortable with supporting it.

“This is a large transmission portfolio for SPP, but it should not be a surprise,” McIntire added.

SPP COO Lanny Nickell said that during the MOPC’s discussion of the plan, he leaned over and asked the committee’s chair, Alan Myers, “When is the last time we had $7.6 billion of investment on the table with this kind on consensus behind it?”

“I don’t remember that. To me, that’s remarkable,” Nickell said. “It’s remarkable that the members all see value for the most part. Now, I know there are some that are concerned about certain projects, and you know the magnitude of cost associated with certain projects, but for the most part, the support for the projects that are in this portfolio is fantastic.”

The portfolio’s size is driven by rapidly increasing and electrified oil and gas load in the Southwest and the Dakotas, some population growth, and the usual wave of data centers and crypto miners. SPP said the ITP considered a “uniquely sharp increase” in load at multiple sites across the SPP footprint, compared to previous ITP assessments, and used the information to inform decisions made while crafting the portfolio.

The 2024 assessment’s Year 2 load is up 9.7% and 12.9% for the 2023 ITP’s Year 10 respective summer and winter projections. It projects a 25% increase in demand by 2030, a nearly 14 GW increase from its 2023 record peak of 55.89 GW. According to SPP’s report, “minimal load growth” has been accelerated by new customers asking to be connected to the grid as soon as possible.

“Uniquely sharp” load increases in New Mexico led to staff’s recommendation for SPP’s first 765-kV line, the Phantom-Crossroads-Potter project from the Texas Panhandle to southeastern New Mexico. Staff said the project has a $4.1 billion net adjusted production cost value beyond its $2.13 billion cost and a 3.1 benefit-to-cost ratio in Year 40.

Staff also incorporated extreme winter weather scenarios into its latest ITP after two recent storms stressed the grid with low temperatures from the Canadian border into the Texas Panhandle. The extended cold temperatures led to above-normal energy use, fuel availability issues and in 2021, the first directed load shed in SPP’s history.

SPP identified and recommended notifications-to-construct for projects to help support the system during extreme weather events.

“We’ve needed to address the resilience issue after Winter Storm Uri and Winter Storm Elliott for a couple of years,” Nickell told RTO Insider. “That has been something that needs to be addressed, and [members] recognize this does that. They not only appreciate the benefits of reducing congestion, but they also appreciate the fact that it solves the reliability and resilience needs that we needed to address.”

Stressing that he was not speaking for all members, Nickell said the $7.65 price tag was a “secondary component” because of the ITP’s huge value to the SPP grid.

Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy, complimented SPP for using “decision quality” concepts and including it in the assessment’s analysis.

“I can’t stand in the way of what the analysis has shown here, but I do think SPP has done a good job,” he said.

Wise told RTO Insider that according to a back-of-the-envelope calculation and under certain conditions, the ITP could cost Golden Spread’s members more than $1 billion in additional transmission costs over the next 40 years. He attributed the lack of discussion over the costs to transmission users not understanding the ITP assessment’s assumptions.

“These are 40-year investments,” he said. “Who bears the risk if the load doesn’t come?”

SPP’s ITP still pales in comparison with MISO’s first two long-range transmission plan (LRTP) portfolios, which have a combined cost of nearly $32 billion. MISO is advancing the LRTP package for its board’s approval at the end of the year. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)

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FERC Approves NERC, RE Budgets for 2025

FERC gave its assent at this week’s open meeting to NERC’s 2025 Business Plan and Budget, along with those of the regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR24-5).

The commission also granted a request by NERC and WECC to fund the Western Transmission Expansion Coalition’s (WestTEC) transmission planning study over the next two years by releasing $2.2 million in total from the Peak Reliability Donation Reserve and approved the REs’ use of penalties to grow its financial reserves and reduce its 2025 assessments.

The ERO submitted the budgets to the commission following their acceptance by the ERO’s Board of Trustees at its August meeting in Vancouver. (See “Budgets Headed to FERC,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) NERC CFO Andy Sharp said at the meeting that the final budgets are “materially consistent” with NERC’s three-year projection.

NERC’s 2025 budget is set to rise 8.2% over the previous year to $123 million, according to the ERO’s August filing. Drivers of the increase include an expected need to hire 13 new employees in reliability standards development, enforcement, the Electricity Information Sharing and Analysis Center, and other areas; investments in the ERO’s technology strategy; and planned increases in meetings and travel costs. The E-ISAC’s budget is also set to grow from $41.1 million to $43.8 million.

The budgets for the REs and WIRAB are set to grow as follows:

    • Midwest Reliability Organization — from $24.9 million to $26.8 million
    • Northeast Power Coordinating Council — $22.1 million to $25.7 million
    • ReliabilityFirst — $31.3 million to $33.4 million
    • SERC Reliability — $32 million to $35.4 million
    • Texas Reliability Entity — $19.2 million to $20.3 million
    • Western Electricity Coordinating Council — $35.4 million to $39.3 million
    • WIRAB — $831,492 to $831,561

The ERO’s total assessment for 2025 is to rise to $270.9 million, up from $241.4 million in 2024. This includes $108.4 million for NERC and $128.3 million in combined assessments for the REs and WIRAB.

WECC and NERC’s requested funding for the WestTEC project will see progressive releases from the funds donated by Peak Reliability upon its dissolution in 2019, with $500,000 released in 2024, $1.5 million in 2025, and $200,000 in 2026. The WestTEC study is to take place over the next two years and is intended to produce transmission portfolios for 10- and 20-year planning horizons. (See WestTEC Seeks to Close $2.1M Funding Gap Despite DOE Boost.)

NERC said the withdrawals will leave a balance of just over $1 million in the Peak Reserve.

Commissioner Judy Chang spoke approvingly about the project at this week’s meeting, calling WestTEC “a collaborative, voluntary interregional planning initiative” that will help meet the long-term needs of the Western Interconnection.

“The Western markets [have been] evolving over the last few years and will continue to evolve in the future … [WestTEC] is very valuable, and I think it’s a good use of Peak Reliability funds to support reliability across the West,” Chang said. “I look forward to seeing the results of those efforts, which [are] also being supported by funds from the Department of Energy.”

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CAISO Q1 Prices Down Sharply Despite NW Cold Snap, DMM Reports

First-quarter electricity prices in CAISO markets were down sharply from the same period in 2023, despite sharp spikes during the January cold snap in the Pacific Northwest, the ISO’s Department of Market Monitoring said Oct. 17.

January’s extreme weather events were the “major story for the wholesale electricity markets in the first quarter of 2024,” Ryan Kurlinski, a DMM senior manager, said during a market issues and performance meeting covering Q1.

The winter event saw Pacific Northwest and Intermountain West balancing authority areas hit an average of about $150/MWh in the Western Energy Imbalance Market (WEIM), compared with $65/MWh in other BAs in the market. As a result, transfer capacity in the WEIM was frequently constrained, preventing lower-priced marginal energy in southern areas from setting lower prices in the north, the DMM found.

Lower natural gas prices across the WEIM compared with Q1 2023 drove decreases in average electricity prices, despite the cold weather events. Prices at both California natural gas trading hubs decreased by more than 60% compared with 2023, helping undercut average power prices by 53%.

“In Q1 of 2024, after we get past the severe cold weather event up in the Pacific Northwest and into mid- and late January, prices significantly drop across the WEIM,” Kurlinski said. “Even with the severe cold weather event, high January prices in the Pacific Northwest and Intermountain West were about 20% lower in Q1 2024 on average compared to Q1 in 2023.”

Congestion and price separation between the Pacific Northwest and other BAAs continued into February and March, though prices were still lower than the previous year.

Congestion played a large role in market impacts during the January cold snap. Historically, congestion rent in the CAISO BA has been in the import direction over the interties, but Q1 saw a “huge spike” in export congestion rent over the ISO’s intertie constraints, symbolizing another one of the “most interesting and major stories of Q1 2024,” Kurlinski said.

“In Q1 2024, intertie congestion rent exploded to $133 million [from $13 million a year earlier]. $130 million of that was in the export direction,” most of which was on the Malin intertie in January, Kurlinski added.

The distribution of that rent has been the subject of ongoing controversy in the West, particularly in the context of the competition between CAISO’s Extended Day-Ahead Market and SPP’s Markets+. (See Powerex Report Expands NW Cold Snap Debate and NW Freeze Response Shows WEIM Value, CAISO Report Says.)

Congestion rent on internal constraints in the CAISO BA in the day-ahead market decreased from $265 million in Q1 2023 to $125 million in 2024.

Additionally, transmission ratepayers lost around $53 million in congestion revenue rent auctions, up from $30 million in Q1 2023.

Kurlinski also noted that real-time balance offset costs in the CAISO area were $51 million in Q1 2024, down from $90 million in 2023. The primary driver of the uplift is load getting paid a different real-time price than generation.

Bid cost recovery (BCR) payments were also down to $41.5 million from $80.3 million in Q1 2023, largely due to a decrease in the residual unit commitment portion of BCR.