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November 2, 2024

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PJM MIC Briefs: July 12, 2023

Vote on Rules for Generation with Co-located Load Deferred

VALLEY FORGE, Pa. — The Market Implementation Committee delayed voting on five competing proposals to allow generators that provide a portion of their output to co-located load to retain their capacity interconnection rights (CIRs).

The discussion — brought by Brookfield Renewable and Exelon, later Constellation — explores the creation of rules allowing a generator to serve highly interruptible load not directly interconnected to the grid, while still being available to switch to serving PJM when called on to meet its capacity obligations. (See “Discussion Continues on Capacity Offers for Generators with Co-located Load,” PJM MIC Briefs: June 7, 2023.)

MIC Chair Foluso Afelumo made the determination to delay the vote based on stakeholder input and not hearing any objections during Wednesday’s meeting.

Constellation Vice President of Market Development Bill Berg said the company has been engaged in outreach with other package sponsors in the hopes that a compromise can be reached between the five options. The Advanced Energy Management Alliance (AEMA), PJM, the Independent Market Monitor and Exelon are the other four sponsors.

“I do think that it is in our stakeholders’ best interest to give it one more month to try to reach some compromise, because my fear is that this will end up at FERC,” Berg said. “…we are reaching out to anyone and everyone we can talk to, particularly some of the package sponsors to see if there’s a path forward on at least some of these issues.”

Exelon’s Sharon Midgley also supported delaying the vote for an additional month, saying she’s continuing to field questions from stakeholders about how the Exelon package would function.

PJM’s Tim Horger said he hadn’t heard of any specific changes being considered for any of the packages and would have been comfortable moving forward with a vote last week, but was supportive of any consensus building that could be done.

Four of the packages include two versions, addressing both co-located load without receiving direct service from the PJM grid and a second for interconnected loads, each of which would have required a second vote with the possibility of the end result being components from two different sponsors being selected. The AEMA proposal does not recognize a distinction between co-located load with or without grid service and would treat both the same.

First Read on Reactive Power Compensation Proposals

During the MIC’s first read last week, stakeholders discussed four packages that would revise the compensation structure for reactive power.

Danielle Croop, PJM’s facilitator for the Reactive Power Compensation Task Force, said the status quo system uses the “AEP methodology,” which identifies equipment at generators that support reactive capability, and each generator is required to make a cost-of-service filing at FERC, many of which result in “black box” settlements.

PJM Assistant General Counsel Thomas DeVita said FERC attorneys have said PJM reactive filings make up a significant portion of their caseload and the commission may seek a resolution of its own.

“If we don’t end this process with a solution there is a significant risk that FERC will act on its own and we will be here again in short order,” he said.

Croop said compensation also is not tied to generators’ performance in supplying reactive power and it sometimes has to provide make-whole and opportunity cost payments. The proposals aim to create uniform compensation — both for providing reactive service and associated opportunity cost payments, reduce administrative burden and draft new market rule changes to replace the existing procedures in Tariff Schedule 2.

A December 2022 poll at the task force found support among members was strongest for the Clean Energy Coalition proposal, at 63%, followed by the PJM package with 28% support. Two packages from the Monitor received 17% and 16% member support. The poll also found that 62% of responding members did not believe that change to the Schedule 2 compensation method is necessary. The poll received 280 member responses, 37 of which were unique.

The proposals are limited to new generators or facilities entering new compensation agreements, with the task force’s scope precluding changing existing reactive rates. The MIC voted down a proposal to expand the task forces’ scope to include existing service rates last month. (See “Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope,” PJM MIC Briefs: June 7, 2023)

The CEC proposal is based on applying the AEP methodology to resources on a class-wide basis by forming a separate rate for each type of generator. The rates would be posted on PJM’s website, but only the underlying formula would be included in the tariff.

The CEC presentation states that applying the AEP process on a technology-wide basis avoids requiring unit-specific FERC filings and treats all generation comparably. Creating a cost-based compensation structure would incentivize investments in reactive capability that caps payments at the cost of the proxy unit. PJM’s proposal would limit compensation to generators that are capable of providing reactive service on the transmission grid, excluding those that can provide it at the distribution grid level. Payments would be based on demonstrated or tested capability and would seek to recognize that all reactive power (VARs) is the same.

Calpine’s David “Scarp” Scarpignato said existing testing for reactive capability often is difficult to complete given technical limitations on the grid, requiring some generators to schedule multiple tests before one can be successfully administered.

Wade Horigan, a principal of Tangibl, said he believes the PJM proposal would create an incentive for PJM and transmission owners to not change voltage during testing and that running only two tests would not reflect generators’ actual capability to respond to a voltage excursion.

PJM’s Glen Boyle said if generators exceed their capabilities, their parameters and compensation would be increased. If generators don’t perform, their revenues would be withheld for that month and future expected capability would be reduced. He estimated the proposal would require an 18- to 24-month implementation period.

Market Monitor Joe Bowring said the AEP method is archaic and illogical and was designed in 1997 to maximize the allocation of costs to reactive for a utility that was fully cost-of-service regulated. Bowring said a recent FERC order on the same issue in MISO required that all such payments for reactive power be terminated.

“There is no need for a cost-of-service approach in a system that relies on markets. This payment of more the $380 million per year in side payments is unnecessary and should be eliminated,” he said.

The first of the Monitor’s proposals — Package F under the matrix — would immediately eliminate separate cost-of-service payments to all resources and would also remove reactive revenues from the energy and ancillary services offset, resulting in an increase in capacity market revenues. All resources currently are required to provide reactive as a condition of their interconnection service agreements (ISA).

The second proposal — matrix Package H — would start with a flat-rate design, similar to PJM’s, but would fully phase out all cost-of-service payments over a short period and would use the same performance penalty as PJM.

Bowring said doing away with the current settlement process and using the AEP method for all resources, as recommended by the CEC, would result in an approximate doubling of the $380 million per year in reactive costs borne by load. He said the FERC order in the MISO reactive compensation case was clear and there also are additional cases in front of FERC that address the fundamental issues of cost-based rates in a market structure.

Stakeholders Question Scope of Distributed Resources Subcommittee

During an update on the work the Distributed Resources Subcommittee (DISRS) is engaged in, PJM’s Ilyana Dropkin noted that Voltus introduced a problem statement and issue charge in which the demand response provider said it could bring a stronger response to the market if offers could reflect operational parameters such as limits in curtailment duration and a need for downtime between curtailments.

Several stakeholders questioned if the DISRS is the best forum for such discussions and whether it’s appropriate for non-voting committees to consider such topics. Scarpignato said subcommittees have the potential to take up subjects that can result in PJM staff being devoted to topics that may not have support at the standing committee level. He predicted the matter brought by Voltus ultimately will result in an issue charge being approved for discussion at either the DISRS or cost development subcommittee (CDS), but it presents procedural questions.

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NYISO Investigating Storage as Transmission

NYISO has started the process of considering energy storage resources as transmission assets, according to a presentation given to the Installed Capacity Working Group/Market Issues Working Group on July 11.

The ISO will assess existing procedures to evaluate whether ESRs can be treated as regulated transmission assets and what potential rules would be required to operate storage as transmission.

NYISO already identified several issues to the effort, however, including what size or duration of ESRs should be allowed to participate and how “dual-use” storage — resources that could both participate in the markets and act as transmission — should be treated.

Glenn Haake, vice president at renewable energy operator Invenergy, sought clarification on what NYISO’s deliverable would be for this year.

Katherine Zoellmer, market design specialist at NYISO, responded, “This issue discovery will conclude with a recommendation for moving forward, and that is what would be taken into next year’s project.”

Haake also asked if storage will be included as a standalone solution in future public policy transmission need assessments.

“This is something we are considering and working through at the moment,” Zoellmer answered.

NYISO said it will return in a month or two with more information on how the project will proceed and asked that any additional questions, comments, concerns or recommendations be sent to KZoellmer@nyiso.com.

 — John Norris

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DC Circuit Upholds FERC on PJM FTR Rule

The D.C. Circuit Court of Appeals on Friday upheld FERC’s decision to approve PJM’s financial transmission rights forfeiture rule without ordering refunds under previous rules implemented without commission approval.

But the court remanded the case to FERC to provide a fuller explanation of why it did not order a forfeiture exemption for non-leveraged transactions — when a trader’s FTR gains do not exceed the losses incurred from that trader’s virtual transactions (22-1096).

FTRs are financial instruments that allow load-serving entities to hedge the risk of transmission congestion costs and permit financial traders to arbitrage day-ahead and real-time congestion. PJM originally implemented the forfeiture rule in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions.

The commission ruled in May 2021 that PJM’s previous 1-cent FTR impact test, which determines whether the net flow impacts the absolute value of an FTR by 1 cent or greater, to be unjust and unreasonable. FERC approved PJM’s replacement rule in January 2022 (ER17-1433). (See FERC Accepts New PJM FTR Forfeiture Rule, Without Refunds.)

After FERC rejected rehearing requests from FTR trader XO Energy, the traders sought relief in the D.C. Circuit, arguing that the commission’s decision approving the new rules and denying refunds under the old rules was arbitrary.

The D.C. Circuit said XO’s arguments were “ultimately unpersuasive” and that the commission “adequately justified” its decision not to order refunds.

“It considered record evidence submitted by PJM, which explained that calculating refunds would be a difficult task requiring ‘considerable software development and testing work that would take months to complete,’” the court said.

The court was more sympathetic to XO Energy’s contention that the new rule should exempt “non-leveraged” positions from forfeiture because they provide no economic incentive to engage in manipulative conduct.

While it declined to overturn the ruling, the court said FERC had provided only “a brief … inadequate, explanation of why it declined to order a forfeiture exemption for non-leveraged transactions.”

“Although the commission acknowledges that leverage might be one way to determine cross-product manipulation, it states that it opted to allow PJM to employ other means to detect this conduct rather than require exemptions based on leverage,” the court said. “That is the extent of the commission’s explanation. It does not address XO Energy’s position that market manipulation cannot occur when the net losses of a trader’s virtual transaction portfolio exceed the net profits from its FTR portfolio. Nor does it explain why the exclusion of this requirement strikes the appropriate balance between preventing manipulative conduct and not hindering legitimate hedging activity.”

But the court declined to vacate the order, saying instead that FERC could “redress the deficiency of its reasoning by providing a more fulsome explanation for its decision not to order PJM to account for leverage.”

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FERC-state Transmission Task Force Examines Barriers to GETs

Grid-enhancing technologies (GETs) could offer significant savings, but an industry that is conservative when it comes to grid operations and planning needs to get used to them first, regulators heard Sunday at the Joint Federal State Task Force on Electric Transmission in Austin, Texas.

The motivation for expanding the use of GETs is clear, with the electric industry undergoing a massive transformation that will see its share of total energy use expand from 21% today to 39% by 2050, while decarbonizing power generation, said Andrew Phillips, vice president of transmission and distribution infrastructure for the Electric Power Research Institute.

“There are about 400,000 miles of transmission lines 100 kV and above in the United States,” Phillips said. “We’ve been building them at a rate of about 2,000 miles per year; we are going to have to double that rate to meet that goal to integrate all of those lower-cost and also carbon-free renewables.”

Getting more use out of transmission lines and related infrastructure such as substations and transformers through GETs — such as dynamic line rating (DLR), advanced conductors or topology control — would make that work easier, he said. Different technologies would have different uses because the issues around the grid vary depending on the exact infrastructure.

Short lines (30 miles or fewer) are the ones that are impacted by temperature the most and would benefit from DLRs that take into account actual temperatures, wind speed and other conditions, Phillips said. Generally, the industry allows only as much power through such transmission lines as would work on the hottest day of the year with low wind speeds, but more often than not, they could handle more electricity.

Advanced conductors also would benefit such transmission lines because traditional transmission can operate only up to 93 degrees Celsius, while newer technologies can run more than twice as hot. Such new conductors have been available for a decade, but the industry has longer timeframes than that, with utilities needing to know they will last for many decades.

“For the last 10 years, EPRI has been doing tests on all of these new advanced conductors, and developed a test that can be put into a specification, so that utilities can acquire these conductors with confidence and knowing that they will last for 40 or 50 years,” Phillips said.

Shorter lines would also benefit from DLRs, but the industry needs to get accurate data on a range of things that impact transmission capacity, including temperature, wind speed and the amount of sunlight hitting them. Many technologies are available to measure those factors, with EPRI and its industry partners determining what works best and where, Phillips said.

“If it’s going to become a day-to-day thing, where we’re going to incorporate these things, we need standards and specs, just like we’ve got standards and specs for transformers, insulators [and] conductors,” Phillips said.

The changing capacity of transmission lines is something grid operators are not used to, and it implies a greater risk, so they will have to familiarize themselves with that before it becomes common, he added. It only makes sense that grid operators are conservative.

“Why are they conservative? Because you want to make sure the lights stay on, right?” Phillips said. “But that conservatism is a challenge when you’re trying to incorporate a new technology and increase the risk. … Maybe a reasonable risk, but a higher risk.”

While such technologies offer savings, they cannot replace transmission expansion entirely, FERC Commissioner Mark Christie said. DLR is “dynamic,” which he said means it is always changing; sometimes it can free up more capacity, but other times not.

“From a planning standpoint, how do you work in a dynamic [system]?” Christie asked. “We know there’s tremendous potential — we know they can save a ton of money — where and when they work.”

From a long-term planning point of view, predicting the wind in 10 years is just not feasible, but DLRs can be very useful in a more immediate, economic way, where they can be used to bring cheaper supply to customers, Phillips said. Long-term planners still have to use the static rating of the line because the grid will experience times when it is hot and the wind is not blowing.

Real-time operators have some leeway when it comes to DLR because of conductors’ “thermal lag,” so that if the wind stops blowing, they have a couple of hours to update power flows over dynamically rated transmission, Phillips said.

In MISO, the planning process does not account for GETs, and planners are skeptical about factoring them in for the long term, but the grid operator is much more open to them when it comes to operations, said Michigan Public Service Commission Chair Dan Scripps.

“RTOs are in many cases able to institute reconfigurations when there is a pressing reliability issue in real time but are more hesitant to act in a proactive way that is only focused on economic benefits,” Scripps said.

That could change going forward, especially with the ability to use different transmission line ratings for the summer and winter in planning going forward. When the conditions for DLRs are not right, it might make sense to use topology control, with which grid operators can tweak the system by, for example, shutting down one piece of infrastructure that frees up more power flow overall, Scripps said.

A major issue to getting GETs rolled out around the grid is the financial incentives for utilities, which are biased toward spending more capital and thus earning more returns, FERC Commissioner Allison Clements said.

“The short answer to how do you better integrate it is for the commission to require utilities to consider whether or not to use them, and then to align the financial incentives so that they’re encouraged when they’re considering them,” she said.

It is also important to dispel the “myth” that GETs are new technologies that are rife with risks when deployed.

“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” Clements said.

Acting FERC Chair Willie Phillips offered an analogy for how GETs will impact the industry by comparing them to the change from road atlases to GPS programs on smartphones.

“When you think about how to use GPS, you don’t use it like a map,” Phillips said. “You don’t set it on time and forget about it.”

The software will reroute drivers around traffic jams and to quicker routes to their destination, with drivers using GPS at every turn throughout their journeys.

“I think that’s exactly how we should use GETs,” said Phillips. “We should use it an interconnection queue phase; we should use it during construction — I say ‘use,’ [but] I mean ‘consider.’ We should consider it during the construction phase. We should consider it after construction and during implementation.”

Just before the task force meeting, Grid Strategies released a report showing growing congestion costs around the country, with $12 billion in RTO markets during 2022 and more than $20 billion around the country, Phillips noted.

“If we can use GETs to bring that number significantly down, I think it’s incumbent upon regulators to do just that,” he added.

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FERC Reverses Course on SPP Byway Cost Plan

After rehearing arguments raised by several SPP members, FERC last week unanimously reversed an October decision that established a process for SPP to allocate “byway” transmission projects on a case-by-case basis.

In a July 13 order, the commission rejected SPP’s proposed methodology without prejudice and dismissed a November compliance filing as moot (ER22-1846).

FERC said the grid operator failed to prove its proposal to regionally allocate 100% of a byway facility’s costs on a postage-stamp basis would result in outcomes that are just and reasonable and not unduly discriminatory or preferential.

SPP currently allocates one-third of the cost of byway projects — lines rated at 100 to 300 kV — to the RTO’s full footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide. Its proposal would have allowed entities to seek exceptions, which would be approved by the RTO’s Board of Directors, to the cost allocation process for byway facilities. (See FERC Approves SPP Cost-allocation Waiver Plan.)

Transmission-owning members Southwestern Electric Power Co., Public Service Company of Oklahoma, Southwestern Public Service, Oklahoma Gas & Electric, City Utilities of Springfield (Mo.), Kansas City Board of Public Utilities and Missouri Joint Municipal Electric Utility Commission filed rehearing requests in November.

The TOs argued that the board’s secret votes, which are conducted after the Members Committee votes publicly, raised the risk that it would approve or deny waivers on a discriminatory basis.

FERC agreed, saying SPP’s proposal continues to grant the board “too much discretion” in allocating byway facilities’ costs because it doesn’t require the directors to approve a reallocation request if it doesn’t meet three criteria.

“The SPP board could deny a requested reallocation where SPP staff has determined that the criteria are met or, conversely, approve a reallocation where SPP staff has determined that the criteria are not met,” the commission said. “The SPP board’s discretion to make decisions that are potentially inconsistent with whether the criteria set forth in the tariff are met could result in unduly discriminatory outcomes.”

FERC said the discretion provided to the SPP board “is not similar” to cost allocation waivers under SPP’s transformer waiver process. It said the RTO’s proposal would make all byway transmission projects eligible to request waivers, leading to an “expansive” list of eligible facilities and a “far-reaching scope.”

Commissioners James Danly and Mark Christie, who dissented in the original 3-2 decision in October, concurred this time in separate opinions.

“SPP sought to arrogate to itself unfettered discretion in socializing the costs of ‘byway’ transmission projects,” Danly wrote. “As today’s issuance acknowledges, the directives in the underlying order failed to render an otherwise unjust and unreasonable proposal just and reasonable.”

Christie noted that he dissented from the original order and that state support for the new cost allocation proposal was “not uniform,” with four states being on the record as opposing SPP’s suggestion.

“Should SPP seek to file another version of its cost allocation for these types of projects, it is my hope that any such new cost allocation will earn the support of all states to which costs could be allocated,” he said.

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FERC Approves Incentives for NIPSCO’s MTEP Lines

FERC on Friday approved Northern Indiana Public Service Co.’s (NIPSCO) request for transmission incentives on two lines it is building under the MISO Transmission Expansion Plan (MTEP).

NIPSCO is building the Indiana portions of Project 15 and the entirety of Project 16, both of which were approved under MTEP 2021. In the order Friday, the utility won approval of 100% of prudently incurred construction work in progress (CWIP) and the abandoned plant incentive, allowing it to collect costs if the projects are canceled for reasons outside the utility’s control.

Project 15 involves upgrading an existing single-circuit 138-kV line to a double-circuit 345/138-kV line and upgrading a related substation. Project 16 spans northern Indiana and increases transmission capacity in both directions. Both projects are expected to be done by June 1, 2029, at a total cost of $280 million, which represents a 21% increase in the utility’s current transmission plant value.

NIPSCO said FERC has granted such incentives to similar regionally planned projects in the past. The CWIP incentive will help improve cash flow, enhance rate stability and lower rate shock concerns.

“We find that NIPSCO has demonstrated that the requested incentive is tailored to the risks and challenges faced by the projects,” FERC said. “We also find that the approval of the CWIP Incentive will bolster NIPSCO’s financial metrics, help ensure its current credit rating, and enable its participation in the projects.”

The record indicates that completing the projects will put pressure on the utility’s finances and CWIP will ease that, FERC said.

A group of industrial customers had asked the commission to deny the CWIP request, arguing that FERC’s transmission notice of proposed rulemaking is considering changes to CWIP.  But the commission rejected their reasoning, saying the potential rule change still was prospective and thus had no impact on NIPSCO’s request.

In approving the abandoned plant incentive, FERC said NIPSCO made the case that the projects face certain regulatory, environmental and siting risks that are outside of the company’s control and could lead to project abandonment. FERC said approval will address those risks and protect NIPSCO if the lines are canceled.

The order drew a concurrence from Commissioner James Danly, who wrote only to sympathize with a lengthy dissent from Commissioner Mark Christie who wants to see changes in how FERC awards the CWIP incentive.

“I would have set NIPSCO’s transmission rate incentives filing for hearing before an [administrative law judge], as the evidence industrial customers have presented casts serious doubt on whether NIPSCO’s requested CWIP Incentive and Abandonment Incentive are tailored to address the risks and challenges of the projects,” Christie said.

In other transmission incentive orders, Christie has questioned whether granting CWIP, abandoned plant incentive and other incentives had become “nothing more than a check-the-box exercise” and the NIPSCO order realized those concerns.

The industrial customers noted that NIPSCO’s owner, NiSource Inc., has sold 19.9% of the firm to Blackstone for $2.15 billion, which includes $250 million in working capital — or about 89% of the estimated cost for the two transmission projects. The utility argued that the customers failed to show how the minority sale proceeds would offset the financial pressure of building the lines.

“NIPSCO appears to ask this commission to pay no attention to the big pile of money that would result from the proposed sale,” Christie said. “I fail to see how the answer as to whether a planned $250 million infusion in working capital would mitigate NIPSCO’s financial risks should not be of interest to this commission or potentially affect the commission’s calculus on whether NIPSCO’s requested incentives are tailored to meet its risks and challenges.”

Setting the case for hearings before an ALJ would have given FERC a chance to explore the financial status of NIPSCO in greater detail, he said. The CWIP incentive turns customers into a bank for the project while the abandoned plant incentive makes them an insurer, but they do not get any benefits from that, he added.

“Revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.

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NYC to Fall 446 MW Short for 2025, NYISO Reports

New York City faces a reliability margin shortfall of up to 446 MW in 2025 due to plant retirements and the delayed completion of the Champlain Hudson Power Express, NYISO said Friday in its Short-Term Assessment of Reliability (STAR) for the second quarter.

The STAR report for the five-year period ending April 15, 2028, forecasts rising loads due to increased electrification of transportation and buildings, continued economic growth following the pandemic and the expected retirement of generators under the state Department of Environmental Conservation’s “peaker rule,” which took effect in May.

NYISO CEO Rich Dewey told the New York State Reliability Council Executive Committee Friday that the ISO is projected to fall short of its transmission security margin, a measure of the power system’s ability to withstand disturbances such as short circuits or unanticipated loss of a generator or transmission line, while continuing to supply and deliver electricity. Dewey said the CHPE, which will deliver hydroelectric power to New York from Quebec, “would solve this problem, but its in-service date slipped to the spring of 2026.”

DEC’s peaker rule, approved in 2019, is intended to limit nitrogen oxides (NOx) emissions from simple-cycle combustion turbines.

As of May, 1,027 MW of affected peakers have deactivated or have limited capacity, while an additional 590 MW of Zone J peakers are expected to be impacted by the DEC’s rule beginning May 1, 2025.

Under baseline weather conditions (95 degrees Fahrenheit) in 2025, the ISO said the higher bound of expected demand will result in a deficiency of 446 MW over nine hours. The deficiency would be “significantly greater” if the city experiences a heat wave (98 F) or an extreme heatwave (102 F), the ISO said.

If the CHPE experiences further delays, more fossil fuel plants become unavailable, energy demands exceed forecasts or significant extreme weather events elevate loads, reliability margins could “continue to be deficient for the 10-year planning horizon,” the report said.

New York state’s growing electric system demand threatens future security margins. | NYISO

Because the DEC anticipated that peakers may need to remain online longer than required, it authorized NYISO to order a two-year extension through 2027 and an additional two-year extension through 2029, should these plants be needed for reliability.

Both Dewey and the report, however, emphasized that keeping the peakers online is a “sub-optimal solution” and would  be used only after NYISO exhausts all other possibilities.

Dewey said NYISO will work with transmission owner Consolidated Edison to develop solutions and will evaluate proposed solutions that will be solicited from developers throughout the summer. NYISO will review submissions, which could include generation and demand response, in the fall and decide on the best way forward during November.

Dewey confirmed that NYISO likely would return to the July 25 Electric System Planning Working Group with a more comprehensive statement regarding the near-term reliability need.

Con Ed said it is reviewing the STAR report and “remains committed to providing reliable, safe service for to customers, and supporting the state’s important clean energy transition.”

The report notes that although CHPE will help reliability in the summer, “the facility is not expected to provide any capacity in the winter.”

Statewide Shortages?

The Q2 STAR also found that New York could face a statewide deficiency of up to 145 MW by 2025, which could remain through 2033, because of the assumed unavailability of power plants complying with the peaker rule.

The ISO said additional large load interconnection projects in western and central New York are expected to increase 2025 demand by 764 MW. “If CHPE does not begin operation, the statewide system margin is projected to be deficient for all years 2025 through 2033 when considering the additional large loads,” according to the report.

During the NYSRC EC meeting, attendees worried about the Q2 STAR’s findings and questioned how projected deficiencies might impact NYISO’s future planning considerations.

Two attendees inquired about the peaker rule and whether it was simply easier or more economically viable to allow these emissions-producing plants to stay online.

Zach Smith, NYISO vice president of system and resource planning, again confirmed that extending the peaker rule was a “last resort,” and responded that this option would be selected only after “NYISO considers the backstop solution Con Ed is required to provide and reviews all solicited proposals.”

Mark Younger, president of Hudson Energy Economics, asked if NYISO has been providing adequate market demand signals to its resources and would reconsider current price signals to be based on more long-term forecasts.

Forecasted energy demands for NYC | NYISO

Dewey responded, “I think that that will be the subject of a lot of discussion over the next year and as we undergo the next demand curve reset.” The DCR occurs every four years and updates the assumptions that determine the installed capacity demand curves. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.)

Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, asked whether NYISO would give greater consideration to nuclear resources.

Dewey responded that the Climate Leadership and Community Protection Act’s scoping plan included a notice on how nuclear energy should be investigated.  “Nuclear development could be solution for these challenges … but I am curious to see if [nuclear] gets any additional traction in discussions at the … Public Service Commission,” he added. The PSC recently ordered staff to identify technologies, like nuclear or hydrogen, which could keep New York in CLCPA compliance. (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)

Wes Yeomans, an NYSRC consultant, asked about the STAR’s statewide findings and if that future reliable marginal deficiency requires any immediate action by the ISO.

Smith answered that “the statewide margin is for informational purposes at this point and there is no action to take at this time,” adding, “we’re providing this as information of basically a need possibly to come.”

Gavin Donohue, CEO of the Independent Power Producers of New York, released a statement on the STAR’s findings, saying, “the pace of play is not keeping up with pace of promises, and this report makes that clear.”

“There have been repeated cautions from the NYISO regarding grid reliability, and this report highlights the reality that generator retirement cannot outpace the addition of new generation with the attributes needed by the NYISO to maintain reliability,” he added.

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Massachusetts Considers Legislation to Ban Gas in New Buildings

The Massachusetts Joint Committee on Telecommunications, Utilities and Energy (TUE) held hearings last week on several bills that would expand the state’s 10-municipality demonstration project allowing cities and towns to ban fossil fuels in new buildings and major renovations.

The TUE Committee also took public testimony on a range of bills promoting building electrification and targeting fossil fuel consumption in buildings more broadly as the state looks to cut building sector emissions and meet its statutory climate goals.

Climate, public health and environmental justice advocacy groups spoke in favor of bills promoting electrification, while they opposed bills that would promote the use of biomethane or blended hydrogen in buildings.

Representatives from the gas, biofuel, heating oil and real estate industries, along with labor groups representing gas workers and plumbers, generally opposed the electrification bills and supported the inclusion of alternative and low-carbon fuels in building decarbonization programs.

The committee helped to craft an omnibus climate bill in 2022 that created a demonstration project allowing 10 municipalities in Massachusetts to ban fossil fuel combustion in nearly all new buildings. State law prohibits most towns from implementing all-electric building codes, based on a ruling by former state Attorney General Maura Healey (D), who is now governor.

Clean energy advocates are now pushing to expand the 10-town program, with many hoping to expand the option, or even pursue an all-electric code for new buildings, statewide. The 10-town limit agreed upon in the previous session was a political compromise between the legislature and then-Gov. Charlie Baker (R). Advocates hope the changing political makeup of the state, along with the ever-increasing need to reduce emissions, will spur the program’s expansion.

“We all know the urgency of action,” said Northampton City Councilor Alex Jarrett. “On Monday, I stood next to a farmer as she watched her equipment and her crops get washed away by what looks to be the third-highest flood event since 1950 on our local Mill River. All of her effort for the season was gone in a few minutes.”

Representatives of cities including Northampton, Salem, Somerville and Worcester expressed their desire to join the demonstration project, but they worried they will be unable to if it is not expanded. The demo gives priority to the 10 municipalities that pursued local bans prior to the 2022 law. Nine of the 10 municipalities are likely to be included in the project, leaving one open spot for additional applicants. And Boston also has expressed its interest in joining.

“It doesn’t make sense to build new buildings that will need to be retrofitted before the useful life of their heating, cooling and cooking infrastructure is through,” Jarrett said.

Advocates argued that it is unfair to allow disproportionately wealthy, white communities to participate in the demonstration project while lower-income communities of color are excluded.

“We’re a major environmental justice community; we shouldn’t have to wait,” said Worcester City Councilor Etel Haxhiaj, noting that the impacts of climate change disproportionately impact vulnerable low-income, nonwhite and disabled residents.

“Without state authorization to restrict new fossil fuel infrastructure in our city, we are completely unable to address our most significant source of emissions: our buildings,” Haxhiaj said.

Along with the need to reduce emissions, advocates for expanding the program cited the public health risks of burning fossil fuels like natural gas and propane in buildings.

Climate advocates from Mothers Out Front and Gas Transition Allies testify to legislators. | Massachusetts Joint Committee on Telecommunications, Utilities and Energy

“The evidence for the harms of gas stoves in homes related to pediatric childhood asthma is robust and has been well known for quite some time, with an increased risk of 42% in children that live in homes with gas stoves,” said Dr. Wynne Armand, associate director of the MGH Center for the Environment and Health and assistant professor at Harvard Medical School.

Armand highlighted a recent study that found gas stoves release significant levels of the carcinogenic chemical benzene during combustion, as well as a 2022 study that found uncombusted gas in the Boston area contained 21 chemicals known to be toxic to humans.

“This is an equity issue,” Armand said, speaking about her experience practicing primary care in Chelsea. “I see this every day, where my community has one of the highest rates of asthma in children, as well as the worst asthma outcomes and higher [emergency department] visits.”

Sen. Mike Barrett (D), chair of the TUE Committee, expressed his support for expanding the demonstration project and said he was in favor of allowing more towns to join during last year’s legislative session.

“Ten isn’t arbitrary, and it wasn’t the number favored by original proponents; it was what we could get,” Barrett said, adding that the legislation promoting the demonstration project originated in the Senate and that proponents may face greater opposition in the House of Representatives.

Meanwhile, those opposing the demo’s expansion include National Grid; the Propane Gas Association of New England; the Massachusetts Energy Marketers Association; the real estate association NAIOP; the Homebuilders and Remodelers Association of Massachusetts (HBRAMA); the Northeast Hearth, Patio and Barbecue Association; Plumbers & Gasfitters UA Local 12; and United Steelworkers Local 12012.

“We urge you to think twice and go slow before expanding the 10-community fossil fuel ban program because of the difficulties that already homebuilders are running into trying to electrify our homes,” said Benjamin Fierro, a lobbyist testifying on behalf of HBRAMA.

Fierro highlighted the results of an industry-sponsored report from the Wentworth Institute of Technology, Massachusetts Institute of Technology and HBRAMA that found that the state’s ‘municipal opt-in specialized stretch energy code’ — which features strict energy-efficiency standards but stops short of mandating electrification of new buildings — could increase the total costs for the construction of single-family homes by 1.8 to 3.8%.

Andrew D’Angelo, executive director of the Greater Boston Plumbing Contractors Association, argued that his organization was not coming to legislators “as shills to the fossil fuel industry or large corporations. We come here as working people and contractors that employ those people with concerns that some legislation, while well intended and altruistic, will come with some unintended consequences for families across the state.”

Tim Fandel of Local 12 advocated for an “all-of-the-above approach” to reducing emissions.

“In the absence of utilizing every option we have at our disposal, there is a real risk in not achieving the intended objectives — and yes, natural gas will play a role in our energy portfolio for many years to come,” Fandel said.

Kevin O’Shea, director of government affairs at National Grid, echoed this position, opposing the expansion of the 10-town demonstration project along with legislation that would impose a clean heat standard on the state’s gas utilities. The proposed standard would not allow utilities to comply using fuels like biomethane or blended hydrogen.

“It is too early to take viable decarbonization off the table that may be needed to meet the 2050 net-zero targets,” O’Shea said.

Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, argued that blending biomethane — also known as renewable natural gas (RNG) — and hydrogen into the gas network “would significantly impair the state’s ability to cost-effectively decarbonize the building sector.”

Citing the “optimistic” estimates of the American Gas Foundation, Butterworth said biomethane from waste sources could cover only about 5% of current U.S. gas demand.

“Increasing RNG production beyond this level would require the use of highly controversial resources including energy crops and gasification of agricultural and forest residues. These forms of RNG production that rely on the intentional production of methane simply shouldn’t be on the table,” Butterworth said, citing the “lack of any clear GHG-reduction benefit and tradeoffs associated with land, water use and food production, to name a few.”

As legislators consider a clean heat standard bill, the Massachusetts Department of Environmental Protection (DEP) has also begun developing a clean heat standard while soliciting public feedback featuring many of the arguments that played out in the TUE hearings. (See Mass. Stakeholders Debate the Scope of Clean Heat Standard.)

Opponents of the legislation argued that the development of the standard should be left to the DEP, while advocates said the bill would provide important guardrails for which compliance pathways are included in the standard.

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SPP Markets and Operations Policy Committee Briefs: July 10-11, 2023

Members Endorse Winter Resource Adequacy Requirement for 2024/25

OMAHA, Neb. — SPP stakeholders last week endorsed a tariff revision request that adds a winter resource adequacy requirement for load-responsible entities (LREs) bound by the grid operator’s recent planning reserve margin (PRM) increase.

However, the measure approved by the Markets and Operations Policy Committee during its July 10-11 meeting is likely to encounter headwinds from SPP’s state regulators and the Board of Directors when they hold their quarterly meetings next week.

The revision request (RR549) applies the same level of validation, study and assessment requirements to the winter season (December through March) that currently applies to the summer season, including a deficiency payment for capacity shortfalls. The measure also assigns an annual deficiency payment to prevent duplicate payments for the same capacity within an annual timeframe.

The tariff change met MOPC’s 66% averaged approval threshold at 67.2%, with 87.5% of transmission owners and 47% of transmission users voting for the revision. It is effective for the 2024/25 winter.

MOPC chair and ITC Holdings’ Alan Myers (middle) guides the discussion flanked by SPP’s Emily Pennel and Lanny Nickell. | © RTO Insider LLC

Director Steve Wright signaled to committee members that RR549 almost assuredly will meet resistance before the Regional State Committee and board next week. He said he was concerned about modified language that American Electric Power offered during the discussion and was accepted by the sponsoring stakeholder group as a friendly amendment. He said adding the PRM’s calculation to the tariff “exposes it to litigation at FERC.”

“That was a tough discussion with respect to whether to move forward now or try to perfect the resolution,” Wright said. “The discussion is there; the debate is there; the members came to a decision. Rather than adding a process requirement regarding the calculation of the PRM with a fairly vague standard and putting that into the tariff … I think that deserves a lot more discussion. For me, it takes us in a different direction. I hope there will be a continued discussion in the next two weeks.”

Richard Ross, AEP | © RTO Insider LLC

MOPC Chair Alan Myers, with ITC Holdings, said the Cost Allocation Working Group’s (CAWG) original version of the tariff change could be offered up to the RSC and board. Staff secretary Lanny Nickell said the time between the MOPC and RSC meetings will give staff and legal an opportunity to develop alternatives to the amended language.

AEP’s revisions require transmission providers to detail the methodology used in loss-of-load expectation studies and to determine the final PRM value based on their results. It said it was concerned the CAWG’s proposed language facilitates PRM changes without providing LREs adequate time to comply and that neither the tariff nor the planning criteria provide a transparent process for stakeholders to validate SPP’s determination or, on their own, forecast future PRM values.

“‘The final results of the LOLE study’ implies it is a simple formulaic result, when in fact it requires the application of judgment among many results,” AEP’s Richard Ross said.

The PRM was raised last summer and added to SPP’s planning criteria despite pushback from members. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

The summer requirement already is in place this year. According to SPP’s 2023 resource adequacy report, all LREs complied with the summer RAR. Sixty LREs met the new 15% PRM requirement passed last year, and one met the 9.89% PRM requirement because its capacity is at least 75% hydro-based generation.

SPP’s Market Monitoring Unit supports a winter RAR but recommended remanding RR549 back to the CAWG to address its concerns. The MMU said that, as written, the tariff doesn’t include language requiring a reasonable expectation of availability for resources used toward RAR; it doesn’t achieve the policy’s goal for the deficiency payment; and the deficiency calculation does not send the appropriate signal to improve available accredited capacity.

MMU Comments Bypassed in Order 881 Compliance

MOPC endorsed a tariff change that SPP legal staff believe complies with FERC Order 881, which directs transmission providers to use ambient-adjusted ratings (AARs) for short-term transmission requests — 10 days or less — for all lines that are affected by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.)

RR565 is a response to FERC’s deficiency letter in May. The commission ruled SPP was noncompliant and directed it to use AARs for any seams-based transmission service; explain its timelines for calculating or submitting AARs; and address systems and procedures so TOs can update their line ratings at least hourly (ER22-2339).

The MMU said the measure does not address some of FERC’s determinations and recommended its own edits. It proposed replacing three sentences approved by the Operating Reliability Working Group (ORWG) with six paragraphs that it said address line ratings’ and methodologies’ “transparency and accuracy.” It also recommended adding transparency indicating the market processes that will use the line ratings.

However, MOPC declined to consider the edits. It passed the ORWG’s recommended version with a 95.56 average.

ORWG Vice Chair Jeff Wells, with Grand River Dam Authority, agreed that the measure’s language doesn’t address all that was required by FERC. He said a procedure manual will outline the process for implementing AARs and “address the unknown.”

“We were trying to keep the tariff concise, to be concise with the wording and what’s required by the tariff,” Wells said, adding that “accommodations” were made to give TOs the flexibility they need to adhere to the requirements “without being burdensome beyond what was required.”

Addressing concerns over the validation process, Keith Collins, vice president of the MMU, said Order 881 requires market monitors to be included. He said SPP will ensure appropriate line ratings or replacements up front, with the MMU taking over after the fact to look at gaming opportunities or market inefficiencies.

MMU’s Keith Collins (right) explains the monitor’s position on Order 881 compliance as SPP’s Yasser Bahbaz listens. | © RTO Insider LLC

“FERC requires the market monitors to validate and have a role in the process. It’s not optional,” Collins said.

He said RR565 likely will be on the board’s consent agenda when it meets next week. MMU staff will evaluate whether to ask that it be pulled off and considered separately, Collins said. The Monitor also could intervene at FERC, which it has done in the past.

“That’s our general practice,” he told RTO Insider. “However, if we’re going to raise a concern with FERC, we would like to ensure that the board has had an opportunity to understand our concerns.”

The commission has granted the RTO an extension to Aug. 1 to make its second compliance filing.

GI Backlog Halfway Completed

SPP celebrated the halfway point of clearing its generator interconnection queue by issuing a press release highlighting its mitigation strategies as paving the way “for the construction of dozens of new resources.”

The RTO credited the backlog mitigation plan with executing GI agreements that will add more than 14.5 GW of new generation to the system over the next four years. SPP has added almost 28 GW of capacity to the system since 2017, when the backlog began.

FERC approved SPP’s backlog mitigation plan, designed to simplify and reduce study timelines, in January 2022. It has completed two cluster studies since, with the five remaining clusters on track to be finished next year. (See “GI Backlog Plan Approved,” FERC Denies Co-ops’ $79M Complaint vs. SPP.)

The queue still has 561 active requests for 112 GW of generation (108 GW of renewable resources) left, with about 220 of the requests submitted last year.

MOPC separately approved RR493, which consolidates language from several existing business practices and the Definitive Interconnection System Impact Studies (DISIS) manual into a standalone GI manual. It also adds GI special studies to the manual and a fuel-based dispatch option to the second study phase.

The measure revises the existing fuel-based dispatch methodology to dispatch non-legacy ITP generators without firm transmission service at the same percentage as non-ITP generators with higher queue priority.

Staff said they had some concerns about RR493’s additional responsibilities in resolving the queue’s backlog, but they supported the measure and would provide a more thorough impact assessment during MOPC’s January meeting.

“SPP staff can support this particular motion because it baselines the manual. … We’re going to have to go through an exercise to determine the overall impact,” said Casey Cathey, SPP’s director of grid asset utilization. “We have actually doubled the very next DISIS, so we’re kind of going into it with eyes wide open.”

SPP Self-reports to FERC

Nickell drew some smiles when he told the committee SPP had filed a self-report with FERC in March. The smirks turned into chuckles when he admitted he had forgotten to pass along the information during the committee’s April meeting.

“My mistake. I’m just now catching up,” he said.

Staff discovered this year that in 2020, they had incorrectly assigned Kansas City Board of Public Utilities (KCBPU) as a transmission-owning member in its electronic ballot tool, rather than as a transmission-using member. Staff reviewed the votes taken since then and discovered the error affected only one vote: approving the PRM’s increase to 15% during the October MOPC meeting. (See “Members Address Resource Adequacy,” SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)

MOPC votes require a two-thirds vote, equally weighted between TOs and TUs, for approval. The PRM measure passed with 66.29% approval, with KCBPU voting “yes” as a TO. Nickell said had the utility been assigned correctly as a TU, the PRM vote would have failed at 65.63%.

The board and state regulators approved the PRM’s increase last July. The October vote simply endorsed RR516 as implementing the increase.

“We think the outcome is inconsequential,” Nickell said. However, because staff changed the vote, SPP reported the change to FERC.

SPP General Counsel Paul Suskie said the industry makes similar self-reports “all the time.”

20-year Tx Assessment Endorsed

Stakeholders unanimously endorsed a 20-year assessment of long-range extra-high-voltage (EHV) transmission needs that says SPP will need between 900 and 1,200 miles of new EHV lines that could enable carbon dioxide reductions of up to 93%.

The study team evaluated 463 solutions during its 35-month analysis. It found the solutions could cost as much as $1.55 billion in engineering and construction costs across its reference case and emerging technologies cases, with a benefit-to-cost ratio of $1.57 billion to $4.35 billion. The assessment does not request notifications to construct, but it did recommend 13 new transmission projects to resolve congestion and other constraints.

The study was due before the end of last year. The next 20-year assessment is targeted for 2027.

“For us to really realize the [20-year assessment’s] value, we’ve got to do these much faster,” said David Kelley, vice president of engineering. “This becomes much more valuable information because, as we all know, our industry is changing much faster than any of us thought was ever possible just a few years ago.”

After receiving feedback from members about media reports that focused on the assessment’s costs, SPP staff clarified that the 20-year study is intended to develop a long-range EHV (considered 300 kV or more) transmission road map for the SPP region. It also identifies projects that economically deliver energy and addresses future industry uncertainty; the identified projects will provide candidates that inform shorter-term planning assessments.

Winter Models to Reflect Uri

The Transmission Working Group updated MOPC on its discussions with the Economic Studies Working Group over the 2024 ITP’s winter weather assessment.

A strike team decided that regional winter models should be more reflective of the February 2021 winter storm (also known as Uri), which had a large impact on the natural gas supply and limited renewables’ production.

Stakeholders have chosen accuracy over precision in using historical data to model the effects on the footprint’s different subregions, similar to a load-forecast approach.

Several other stakeholder groups also briefed the committee:

    • The Project Cost Working Group has created an in-service date delay report that will be added to the quarterly project tracking report and list network upgrades with estimated in-service dates at least one year past. Staff will review the new report with the working group each quarter and provide updates to MOPC and other stakeholder groups as needed. The increased awareness already has resulted in 18 completed and previously delayed upgrades at a cost of $146 million, said group Chair Brian Johnson, with AEP.
    • The Strategic and Creative Re-engineering of Integrated Planning Team’s Consolidated Planning Process Task Force is drafting a white paper to “button up” the first phase of its proposed consolidated planning process following “a lot of healthy discussion,” SPP’s Sunny Raheem said. The stakeholder group still must determine an entry fee rate-structure design for cost-sharing and recovery and transition plan recommendations, and continue developing phase 1 policy recommendations.

Zonal Criteria Voting Changed

Members unanimously approved its consent agenda, but not before National Grid Renewables Energy Marketing pulled RR557 for separate consideration. The measure, which passed with opposing votes from National Grid and two other transmission users, updates the zonal planning criteria voting process so absent and abstention votes no longer are counted as “no” votes and are not included in the final tally.

National Grid’s Margaret Kristian said the smaller denominator creates a low bar for approval with abstentions or absent votes. “We think that the recording of approval should really be in the affirmative on the new policy, and that the kind of default action should not necessarily be to approve without the majority,” she said.

The consent agenda included scope updates to the 2024 ITP that document a new vendor for the long-term natural gas pricing outlook and defining extreme winter weather model scenarios needs; endorsement of a sponsored upgrade study for 161-kV work in Omaha; and nine additional RRs that would:

    • RR521: clarify that market participants registering auxiliary load must ensure that it is consistent with any legal or regulatory requirements applicable to the auxiliary load or the entity serving the load.
    • RR542: define aggregator of retail customers (ARC) and differentiate between certification and attestation requirements for ARCs and other aggregators registering under FERC Order 719.
    • RR543: require market participants registering demand response resources (DRRs) to verify that critical load is not being registered as a DRR and that the registered capacity does not exceed the load’s hourly maximum within the previous year; and clarify the dispute process between the market participant, retail provider and relevant retail regulatory authority for DRRs.
    • RR547: eliminate the need for the MMU to pass an annual revision request updating the variable operations and maintenance escalation index that can be computed from publicly available Bureau of Labor Statistics data.
    • RR548: eliminate the rarely used screening study processes for long-term service requests (LTSR) and delivery point transfers (DPT) and incorporate the DPT into the consolidated planning process.
    • RR552: do away with the ITP manual’s requirement removing the firm service requirement for resource inclusion in the base reliability power-flow models.
    • RR553: ensure all uncertainty product revision requests (RR449, RR496, RR535) are implemented correctly.
    • RR561: clarify the overall multiday reliability assessment (MDRA) process and how the day-ahead market will consume its commitments, how they are compensated through settlements and which resource offer costs are used for recovery.
    • RR569: correct the settlements protocols to ensure multiday minimum run time and settlement calculation cleanup are implemented accurately.
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DC Circuit Sends SEEM Back to FERC

The D.C. Circuit Court of Appeals on Friday remanded FERC’s approval of the Southeast Energy Exchange Market (SEEM) back to the commission for additional proceedings.

The three-judge panel agreed that FERC was wrong to deny initial requests for rehearing of the approval because of the dates on which they were filed, but Judge Neomi Rao split with her two colleagues in a partial dissent and agreed with the commission’s reasoning on two of the specific rules that came before the court.

SEEM members include Associated Electric Cooperative, Duke Energy, Southern Co., Tennessee Valley Authority and others in the Southeast. The market has an algorithm to match excess supply with free transmission every 15 minutes, enabling more frequent transactions among its members. It ran into opposition from parties who argued it was anti-competitive compared to the Western Energy Imbalance Market, let alone a full ISO/RTO.

FERC was unable to agree on whether to approve the SEEM proposal, splitting 2-2, which allowed the SEEM tariff to go into effect automatically. Now it returns to another iteration of the commission with four votes, though with acting Chair Willie Phillips instead of former Chair Richard Glick. (See SEEM to Move Ahead, Minus FERC Approval.)

The case presented a test of a recent change to the Federal Power Act that made such split decisions reviewable by the courts. One issue was whether parties had submitted their required rehearing requests to the commission on time. FERC argued that it had to rule on the case by Oct. 10, 2021, which started the 30-day countdown for rehearing that would end Nov. 9.

However, Oct. 10, 2021, was a Sunday, and it was followed by Columbus Day on Oct. 11, when FERC was shut down. Thirty days after was Veterans Day, which meant FERC was closed again. Advanced Energy United and other parties sought rehearing in filings submitted Nov. 12.

The court ruled in 1989 that deadline dates exclude Saturdays, Sundays and federal holidays, which made Nov. 12 the due date for rehearing requests.

“Accordingly, the commission erred in finding the petition for rehearing of the deadlock order untimely below, and the related orders finding as such are therefore vacated,” the court said.

FERC will have to deal with the rehearing requests’ merits on remand, the court said.

While FERC was split on the order approving SEEM, it was able to vote out a related order on the market’s nonfirm energy exchange transmission service (NFEETS); it also rejected requests for rehearing of that order. The court was able to weigh the merits of those requests. (See FERC Again Rejects Efforts to Overturn SEEM.)

SEEM requires that entities transacting in it have a source and sink inside its footprint, which goes against FERC’s pro forma open-access transmission tariff from Order 888. The old bilateral market was different from the pro forma tariff as well, but the new SEEM rules excluded 65 existing bilateral trading partners that cannot participate in the new market.

SEEM’s backers argued that the geographic limits were needed to implement the 15-minute trades, but the court noted that they could have designed the system differently to more efficiently handle such requests.

“The creation of a new service that — by its design — excludes existing market participants evokes the discriminatory practices against third-party competitors by monopoly utilities that prompted the commission’s adoption of Order No. 888,” the majority said.

It ruled that FERC failed to offer a good enough explanation on how the rules are better than the pro forma tariff and that it will have to explain that better, or explore rule changes, on remand.

Opponents argued that under Order 888, NFEETS made SEEM a loose power pool, which is required to be open to nonmembers. Order 888 qualifies loose power pools as arrangements between more than two utilities where they offer discounted power, specifically mentioning “non-pancaked” rates as a discount.

SEEM charges only one transmission rate for power to cross all of its members’ systems, so the majority found that FERC failed to adequately explain why it was not a loose power pool.

Rao dissented on the NFEETS issue, finding that SEEM’s backers had compelling technical reasons to limit participation to entities within its footprint and that FERC correctly determined it was not a loose power pool.

“NFEETS does not limit access to any currently existing service,” Rao wrote. “Rather, it provides an entirely new service that facilitates valuable short-term energy transactions, resulting in substantial cost savings across the Southeast. The tariff revisions are thus strictly preferable to the existing tariffs.”

She also agreed with FERC that SEEM did not qualify as a loose power pool because it creates the opportunity for new transactions; it does not “in any sense result in a discounted or special rate from existing arrangements.”

“SEEM provides a valuable service by establishing a new market for utilities in the Southeast to engage in short-term energy transactions,” Rao said. “FERC reasonably approved the no-cost transmission service necessary to implement SEEM.”