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November 19, 2024

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National Grid to Pay $512k for Standards Violations

National Grid USA must pay $512,000 in penalties to the Northeast Power Coordinating Council (NPCC) for violations of NERC reliability standards, under a settlement approved by FERC on Friday (NP22-33).

According to the agreement, National Grid — which owns about 8,900 miles of transmission lines and 387 substations and serves about 3 million customers in New York and Massachusetts — admitted to three separate violations. Two involved FAC-008-3 (Facility ratings), and the third PRC-023-4 (Transmission relay loadability). All were self-reported.

At issue with the FAC-008-3 violations were requirements R6 and R8 of the standard. R6 requires that each transmission and generation owner have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology” (FRM), while R8 specifies the information that TOs must provide to reliability coordinators and other stakeholders when requested.

National Grid first realized that it might be in violation of the standard while it was preparing for its annual TPL-001-4 planning assessment and “another related project” in September 2019. Specifically, the entity discovered that “six transmission facilities did not have facility ratings … that were consistent with its” FRM. A subsequent extent of condition review, in which National Grid analyzed the facility ratings for all of its 726 bulk electric system elements in New England and New York, revealed similar issues at 100 facilities.

That was not the last time the utility would unearth ratings discrepancies at its facilities. During an asset baseline pilot in 2021 during which National Grid conducted field visits to 20 substations to verify field conditions, the entity found eight more facilities in which the field conditions did not match the ratings on record (another eight had already been flagged during the earlier review).

National Grid determined that the incorrect ratings had begun “on a variety of different dates,” stretching back to 2007 or earlier. NPCC asserted that because of the long duration, multiple versions of the standard were violated, from FAC-009-1, which took effect June 2007, to FAC-008-4, the currently effective standard.

The violations of R8 were discovered during the same planning assessment in 2019, with National Grid reporting to NPCC that it had failed to provide ISO-NE and NYISO accurate facility ratings for six transmission facilities. An extent of condition review found similar discrepancies at 154 facilities, later determined to span a similar time frame as the R6 violations.

NPCC assessed both the R6 and the R8 violations as a serious risk to bulk power system reliability, noting that incorrect facility ratings cause system operators to operate “with a decreased level of situational awareness in real-time and [monitor] contingencies with reduced accuracy.” Mitigation actions are ongoing and not expected to finish until 2025. They include walkdowns of all 175 BES substations and switching stations in New York and New England, with visual inspections of nameplates, transformers and bus conductor types at each station.

National Grid has already updated facility ratings with NYISO and ISO-NE where possible and updated its FRM “to document how global changes to key assumptions will be implemented and/or applied to existing facility ratings.” It has also begun a semi-annual review in New York “to verify that facility ratings updates made within the previous six months were correctly implemented and documented.”

Relay Setting Slip-ups

The utility’s violation of PRC-023-4 involves requirement R1, which details the criteria that TOs, GOs and distribution providers must use on circuit terminals to “prevent [their] phase protective relay settings from limiting transmission system loadability.” Criterion 1 tells utilities to set relays “so they do not operate at or below 150% of the highest seasonal facility rating of a circuit,” while criterion 2 requires relays to be set “so they do not operate at or below 115% of the highest seasonal 15-minute facility rating of a circuit.”

National Grid notified NPCC in July 2019 that it was noncompliant with R1 because 10 of its protective relay settings did not meet criterion 1 for relay loadability. The following year the utility reported an additional relay setting that did not meet criterion 2, and it reported five more violations of criterion 1 in 2021. In all, there were 16 noncompliant relay settings affecting 13 transmission lines. The infringements began in 2010 and had all been corrected by September 2021.

NPCC determined that the violation posed a moderate risk to BPS reliability: While improper protective relay settings increase “the risk that transmission lines would trip prematurely,” the RE also noted that National Grid is a summer peaking system and the feeder loadability issue affects the winter season.

National Grid’s mitigation actions include applying new settings for appropriate relays and implementing a tracking spreadsheet to ensure PRC-023 compliance among applicable relays. The utility also implemented a new training module for the protection engineering team on completing the new spreadsheet, and committed to update the annual training — next scheduled for January 2023 — to “include the different calculations that exist and when to apply them.”

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Eversource Calls on Feds to Prepare Emergency Actions for New England

New England’s largest utility is piling on to calls for winter help from the federal government.

In a letter to President Biden last week, Eversource Energy (NYSE:ES) CEO Joseph Nolan asked the administration to start preparing for possible emergency action as New England stares down what could be a dicey winter for the region’s electric grid.

“As both an energy company CEO and a lifelong New Englander, I am deeply concerned about the potentially severe impact a winter energy shortfall would have on the people and businesses of this region,” Nolan wrote.

He laid out a problem that has become familiar to energy policymakers in the Northeast: pipeline constraints, a lack of fuel storage capability and a volatile LNG market, which together could mean rolling blackouts if the region sees a period of extreme, extended cold.

Nolan pointed to four possible emergency actions that the federal government could take:

      • a waiver of the Jones Act to make it easier for imported LNG to get to terminals in New England;
      • an emergency order under Federal Power Act Section 202c, which allows the secretary of energy to order “temporary connections of facilities and such generation, delivery, interchange or transmission of electric energy”;
      • an emergency order under the Natural Gas Policy Act, which addresses a “severe natural gas shortage”; and
      • using the Defense Production Act to prioritize domestic energy supplies.

Waiting until an emergency arrives would be too late, Nolan wrote, asking the federal government to start making a plan with the region.

“The need for action now is compelling. Many of the solutions require advance planning because they may require actions by regulators, finding new resources, chartering vessels, arranging for additional fuel deliveries and other yet-to-be-identified extraordinary actions,” he said.

Eversource’s request for help follows others in the region, including New England’s governors, who wrote to the Biden administration in August asking for consideration of a Jones Act waiver and work on a new Northeast energy reserve. (See New England Governors Ask Feds for Help with Winter Reliability.)

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Maine Voters to Decide on Upending Utility Landscape in 2023

Maine voters may have the chance to upend the state’s utility landscape and send its two biggest players packing in November 2023.

Our Power Maine, a coalition pushing for a referendum to replace Central Maine Power and Versant Power with a nonprofit, consumer-owned alternative, announced on Monday that it has acquired the signatures necessary to get it on the ballot next year.

The initiative calls for creating a new utility called Pine Tree Power, which it says would be privately operated and controlled by a mostly elected board.

“The company’s purposes are to provide for its customer-owners in this state reliable, affordable electric transmission and distribution services and to help the state meet its climate, energy and connectivity goals in the most rapid and affordable manner possible,” the ballot question would state, if it’s approved by Maine’s secretary of state.

What’s not stated outright in the referendum question, but is a driving force behind the campaign, is that the utilities it aims to push out are some of the most unpopular in the country. In their respective categories in the J.D. Power 2021 Electric Utility Residential Customer Satisfaction Study, CMP and Versant are dead last. Their customers also pay rates that are among the highest in the country.

“It’s this strange inequity where we get what is clearly the worst and least popular service in the nation and pay kind of a lot comparatively for that,” Andrew Blunt, executive director of Our Power Maine, said in a recent interview.

A group of three Maine economists wrote in an op-ed last year that the refinancing and replacement of CMP and Versant would save residents money right away.

Opponents say the initiative would be a costly one for the state.

Versant and CMP have fiercely opposed the initiative; Our Power says the utilities have spent $6 million fighting it. Other business interests in Maine are opposed too.

“This risky $13.5 billion proposal to take over our electric grid will create a tremendously volatile business environment in Maine for years to come,” Dana Connors, president of the Maine State Chamber of Commerce, said in a statement. “Companies will be forced to think twice about investing in our state, and what do customers get in return? Higher rates, a debt three times the annual state budget, unaccountable politicians controlling the state’s critical infrastructure, and no guarantee of better service. Maine businesses depend on safe, reliable, affordable electricity, and we can’t afford to gamble that all away on this proposal.”

CMP parent company Avangrid (NYSE:AGR) has also funded an opposing campaign called No Blank Checks, which also collected signatures in an effort to force a statewide vote on any new government debt over $1 billion, which would apply to the utility buyout, although the exact cost to the state is under debate.

The consumer-owned utility proposal made it through Maine’s legislature in 2021, only for it to be vetoed by Gov. Janet Mills, who claims that her opposition was more about process and specifics of the legislation (which also would have put the question to voters) rather than the underlying idea of replacing the state’s incumbent utilities. (See Mills Tells Maine Legislature to Slow Down on Plan to Replace IOUs.)

“L.D. 1708, hastily drafted and hastily amended in recent weeks without robust public participation, is a patchwork of political promises rather than a methodical reformation of Maine’s complicated electrical transmission and distribution system,” Mills said at the time.

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NYISO OC Approves CY21 Cost Allocations

The NYISO Operating Committee last week approved the class year 2021 (CY21) study report, triggering the 30-day period for generation developers to decide whether to accept or reject their cost allocations for needed transmission upgrades.

Stakeholders expressed some concern over the ISO’s anticipated CY21 schedule, specifically as it relates to whether the additional system deliverability upgrade (SDU) studies for projects will be complete by the 2023 class year’s (CY23) upcoming annual transmission baseline assessment (ATBA) lockdown.

The ATBA is the pre-existing baseline system, which is used to evaluate the addition of the CY projects and identify whether system upgrade facilities (SUFs) are necessary.

Certain stakeholders expressed that they were “unclear” about whether CY21 projects undergoing an additional SDU study would be included in subsequent class years or had “lost their opportunity to participate” in the next class year.

Mark Reeder, representing the Alliance for Clean Energy New York, gave a theoretical timeline of events, attempting to demonstrate how NYISO could not “know what your ATBA base case is if you lock it down” before all the additional SDU study projects in CY21 have accepted or rejected their cost allocations.

Thinh Nguyen, senior manager of interconnection projects, said that “if for some reason the additional SDU studies are not complete in time to join the subsequent class year,” then those projects will need to “pre-emptively request the ISO to join the subsequent class year.” The ISO will not automatically put CY21 projects undergoing an additional SDU study into CY23, and that “projects that don’t request” to be included in CY23 will see their additional SDU study “terminated” when the “subsequent ATBA is locked down.”

Developers who reject their project cost allocation will trigger additional decision rounds in which NYISO will issue a revised study within 14 calendar days that no longer includes those projects. Remaining developers will have an additional seven days to provide the ISO with notice of their election for the revised cost allocations.

This iterative process will continue until all remaining CY21 members accept or reject their cost allocations. Assuming it goes only one decision round, the ISO estimates CY21 ending on Dec. 2 and CY23 beginning on Jan. 3, 2023.

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PJM Stakeholders Reject Clean Energy Requirement for Board

CAMBRIDGE, Md. — PJM’s Members Committee on Wednesday rejected a proposal from the Illinois Citizens Utility Board to require that at least one member of the Board of Managers have clean energy qualifications.

The proposal would have amended PJM’s Operating Agreement to add a qualification that one board member “shall have expertise and experience in the development, integration, operation or management of clean energy resources.” The amendment failed with 32% support, well short of the two-thirds margin required in the sector weighted vote.

Albert Pollard of CUB told the committee in September that PJM’s board needs expertise in carbon-free generation as the grid transitions away from fossil fuels. 

“This is not a proposal to have a clean energy advocate on the board, and I would oppose such a thing,” Pollard said. “This is clean energy expertise. This is someone who, through their leadership, can work with the other experts on the board to call balls and strikes,” he said.

Paul Sotkiewicz of E-Cubed Policy Associates said the focus should be on promoting reliability rather than having expertise in any one form of generation, which he said would introduce potential bias and undermine the board’s independence.

“This would lead to some advocates on the board because let’s face it, everyone comes with some bias,” he said.

Pollard said the amendment would not change the composition of the board as there are currently sitting members who already meet the qualifications the CUB was seeking to add. During the MC’s first read of the proposal on Sept. 21, PJM CEO Manu Asthana and General Counsel Chris O’Hara clarified that the measure would not be adding a dedicated seat, but rather a qualification. (See “Board Member with Clean Energy Expertise,” PJM MRC/MC Briefs: Sept. 21, 2022.)

Adrien Ford of Old Dominion Electric Cooperative said that based on her experience on the nominating committee she believes the existing process is sufficient for determining the experience that would create the strongest board composition. Additional requirements would limit the committee’s flexibility, she said.

“The nominating committee really works to make sure we have the core expertise needed on the board [and] has the flexibility … to fill in what additional experience is needed on the board,” she said.

Jason Barker of Constellation Energy said the amendment would reflect the discussions at PJM’s Annual Meeting regarding the challenges posed by the clean energy transition. Ensuring that the board has expertise in the types of resources that will increasingly dominate the grid will be critical to managing reliability, he said.

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Transmission Conference Focuses on Reliability, Interconnection

WASHINGTON — Transmission stakeholders and federal regulators are concerned about extreme weather and clogged generator interconnection queues, but they’re also encouraged by FERC’s many proposed rulemakings to tackle those issues.

“We’ve probably had more headlines this year in MISO related to resource adequacy and the threat of outages than we’ve had in the last five years combined,” Scott Wright, the RTO’s executive director of resource adequacy and resource utilization, said at WIRES’ annual Fall Conference on Thursday. “The risk profile of the grid is changing significantly.”

Variability and uncertainty have always been a part of managing the grid, he said, but both have increased significantly and faster than expected. “So all of our thoughts and plans at MISO had to be reprioritized and changed.”

The two are related in a way: States are seeking to interconnect more renewables to address climate change, which is increasing the frequency of extreme weather events.

Eric Vandenberg 2022-10-27 (RTO Insider LLC) FI.jpgEric Vandenberg, FERC | © RTO Insider LLC

Eric Vandenberg — recently appointed deputy director of FERC’s Office of Electric Reliability, after serving as deputy director of the Office of Energy Policy and Innovation (OEPI) — gave a keynote speech focused on the threat of extreme weather. He stood in for Commissioner Willie Phillips, who could not attend because of a death in family, according to WIRES.

Vandenberg noted that several regions have come to the brink of load shedding just this year, including an early cold snap in MISO and an extended heat wave in California. “Looking forward, ‘extreme’ does not necessarily mean ‘rare,’” he warned.

Since the beginning of the year, FERC has issued several Notices of Proposed Rulemakings on transmission, including one on planning processes and cost allocation (RM21-17), and one addressing interconnection queues (RM22-14). Both came as a result of a wide-ranging Advance NOPR issued last year, the results of which the attendees of last year’s conference were eagerly anticipating. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)

But FERC also issued proposed rules that would update NERC reliability standards and direct transmission providers to report on their policies for assessing their vulnerabilities to extreme weather. (See FERC Approves Extreme Weather Assessment NOPRs.)

Vandenberg said the NOPRs are designed “to raise that floor” of NERC’s standards “for instances of extreme weather” by making utilities address their vulnerabilities.

Meanwhile, “I don’t need to harp on the need for reform here with this audience; I think it’s pretty obvious to everyone that the interconnection queues are generally pretty backlogged,” said Tristan Kessler, an economist in OEPI. He noted the record number of projects submitted to MISO for interconnection just this year. (See MISO: Record 1,000 Interconnection Requests in 2022.) “So I’m excited to be at your fall 2032 panel to talk about interconnection issues as well.”

Amanda Conner, vice president of FERC and RTO strategy and policy at American Electric Power, asked Wright, Kessler and fellow panelist Cynthia Bothwell, an engineer in the Department of Energy’s Wind Energy Technology Office, whether the commission’s proposal goes far enough.

FERC’s proposed rulemaking on queues would create a first-ready, first-served model for interconnection, which has won wide support. But it would also impose stricter requirements on transmission providers in the form of penalties for failing to meet certain deadlines on completing interconnection studies; RTOs and utilities have not been particularly receptive to these.

Wright said “many things in the NOPR are spot-on,” but some “may not help with efficiency or may cause unnecessary work. … Is FERC going far enough? Well, they certainly proposed things related to very definitive penalties [to which] we would say, ‘Don’t go farther.’”

Bothwell answered that FERC “is doing a great job of getting that conversation going, but we know that the system is changing, and to get to this big transformation, it’s going to happen in steps. And we’re going to learn more … and need additional reforms down the road.”

“It’s definitely not the end of the process for us,” Wright said. “A lot of transmission providers have come to us and proposed other changes … and I think the commission is generally supportive of that.”

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PG&E to Offer Nation’s First V2G Export Rate

Pacific Gas and Electric said Wednesday it had received regulatory approval to establish the nation’s first vehicle-to-grid export rates for commercial electric vehicles, including incentives for early adopters in the program’s first year.

“The V2G export rate promotes EV adoption by providing upfront incentives to help commercial customers offset fleet costs and delivers an innovative solution for these vehicles to export power back to support the grid during peak energy demand periods,” the utility said in a news release.

Electric school buses are a main target of the new rate-setting mechanism.

School buses hold larger batteries than standard EVs and can spend peak solar hours parked and plugged into bidirectional chargers. They can discharge energy to the grid when it is needed most, such as the strained conditions that CAISO has encountered on hot summer evenings in the past three years.

“As large vehicles like school buses and commercial fleets continue to electrify, the opportunity grows for these vehicles to serve as crucial, flexible grid resources to support a more reliable, affordable and efficient energy system,” PG&E said in the news release. “Greater volumes of these vehicles on the road come at a critical time, as peak energy demand challenges California’s grid and novel solutions like V2G emerge.”

The rate-setting mechanism was included in an uncontested settlement between PG&E, the CPUC’s Public Advocates Office, EV advocacy organization Vehicle Grid Integration Council (VGIC), and charging company Electrify America. The settlement was the subject of a proposed decision published Sept. 14 and approved by the CPUC Oct. 20 without discussion.

PG&E first proposed the dynamic, real-time hourly pricing rate structure (RTP rate) for commercial EVs in Oct. 2020.

“The design of the rate to be used in the export compensation pilot is straightforward,” the Sept. 14 proposed decision said. “As with the RTP rate underlying the export compensation rate ‘rider,’ only the components of the generation rate are affected. The design of the export compensation pilot rate rider would delete the revenue-neutral adder currently applied to the RTP rate but would keep the marginal energy charge and marginal generation capacity cost elements.”

PG&E agreed to try to make the export compensation pilot available for enrollment by Oct. 1, 2023. It will operate for three years, unless the CPUC extends it.

The pilot project will include up to $250,000 in incentives for customer enrollment during its first year. Participants will be eligible for incentive payments based on the size of their EV equipment and type of vehicle served, with school buses eligible for an incentive adder.

Equipment of 100 kW or less can receive a base incentive of $1,800 plus a $1,350 school bus adder for a total of $3,150. Equipment greater than 100 kW can get a $3,750 base incentive and a $2,810 adder for a total of $6,560.

PG&E estimates the total ratepayer cost of the export compensation pilot will be between $1.42 million and $1.52 million, the decision said.

“The CPUC’s decision is a strong step forward for Californians and in support of the state’s grid, implementing the nation’s first dynamic export rate for EV charging customers,” VGIC Policy Director Ed Burgess said. “As ever-greater numbers of EVs hit the roads, this innovative rate option will allow EV owners to further benefit from their investment in clean transportation.”

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NYISO RNA Raises Concerns over Timing of Peaker Unit Retirements

[EDITOR’S NOTE: A previous version of this story incorrectly stated that the Astoria natural gas plant is retiring in 2023. Several peaker units based in the Astoria neighborhood of Queens, N.Y., are scheduled to retire.]

NYISO’s draft 2022 Reliability Needs Assessment (RNA) found no reliability issues until 2032 but did identify tightening transmission security and resource adequacy margins across New York, staff told the Management Committee on Wednesday.

Those margins mean generators affected by the state’s so-called “peaker rule” may need to remain operational until either the Champlain Hudson Power Express (CHPE) transmission project or other resources are completed.

The rule imposed strict nitrogen oxide emission requirements on state power plants, which will force many old gas-fired plants to deactivate. It goes into effect May 1, 2023; plants must comply with it by that date or be shut down.

Several members of the committee, which voted to recommend the draft RNA for approval by the ISO’s Board of Directors, expressed concern that certain utilities’ transmission projects will not be completed by the deadline.

“It’s Oct. 26. There are growing concerns about what’s going to happen May 1,” said attorney Doreen Saia, of Greenberg Traurig. Saia was particularly concerned about a Consolidated Edison project being built to account for the retirement of peakers in Queens. “It is critical for the NYISO to — in writing, in a presentation — to confirm that you have been advised that the project is on schedule and will be completed by the May 1, 2023, date. It is not good for the market to have the kind of uncertainty that is sitting out there.”

She said that more transparency around the status of Con Ed’s local transmission plans would alleviate many of the concerns and suggested that the ISO conduct a peaker assessment to help stakeholders better forecast resource planning.

Liam Baker, vice president at Eastern Generation, concurred with Saia, saying that as “the largest owner of assets impacted by the peaker rule,” it is “very hard to make plans” without knowing what the future holds.

Zach Smith, NYISO vice president of system and resource planning, responded that the ISO’s short-term assessment of reliability (STAR) reports have included such assessments since the peaker rule compliance plans were filed in 2020, and that the ISO will continue to get the information across to stakeholders as “transparently as possible.”

Kevin Lang, partner at Couch White, asked when NYISO would “notify developers that they need to stay on” so that they have “enough time to take whatever measures” necessary to remain active and avoid any “gap periods.”

Smith responded that the ISO needs to “continue monitoring this on a quarterly basis” and that these decisions would likely be reported in any future STAR reports.

The ISO also emphasized that the CHPE project is important to the state’s future reliability and that if it is delayed, New York City could see its transmission security margins become deficient by 2028. (See “ISO: Champlain Hudson Critical to NY Reliability in Future,” NYISO Operating Committee Briefs: Oct. 13, 2022.)

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CAISO Approves More Interconnection Enhancements

CAISO‘s Board of Governors on Thursday approved the second and more-complex phase of its interconnection enhancements meant to streamline the addition of resources to its grid and shrink its long interconnection queue.

Applications for new interconnections more than tripled to 373 last year as the state aimed to add more renewable and storage resources to meet its 100% clean-energy mandate by 2045 and bolster system reliability.

“The ISO experienced unseen volumes of projects seeking to position themselves to compete in procurement processes,” CAISO Vice President of Infrastructure and Operations Planning Neil Millar wrote in a memo to the board. “Across the country and in California, stakeholders and regulators have initiated discussions on methods to better accommodate increasing pressure on interconnection processes.”

CAISO started meeting with stakeholders last year in a fast-tracked initiative to “improve its Generator Interconnection and Deliverability Allocation Procedures (GIDAP) and make process enhancements as resource interconnection needs evolve.”

“To date, the ISO has processed nearly 2,000 interconnection study requests, providing interconnection customers with the information needed to make decisions on how to proceed with their projects and to compete for a power purchase agreement with California procurement entities,” Millar wrote. “Of that amount, approximately 200 projects [totaling 24 GW] have gone into commercial operation.

“With the significant acceleration in procurement targets, numerous generator retirements, load growth, and state mandates for non-carbon emitting generation, the ISO’s processes must continue to evolve,” he wrote. “The dramatic increase in competition among suppliers has significantly increased the pressure on the GIDAP.”

The initiative’s first phase focused on simpler, near-term enhancements that had broad stakeholder support. The CAISO Board of Governors approved that phase in May, and CAISO received FERC approval of the changes in August. (See FERC OKs CAISO Interconnection Updates.)

Phase 2 dealt with more complex, long-term enhancements. One involved cost allocation for network upgrades to local systems of less than 200 kV. It would cap costs recoverable from local ratepayers at 15%.

“There is ongoing concern that the current practice for generator-interconnection-driven local upgrades could unduly impact local ratepayers who solely bear their costs,” Millar wrote.

Costs for lower-voltage network upgrades in excess of 15% “will be financed by interconnection customers without cash reimbursement, but with merchant transmission congestion revenue rights if created,” the memo said.

Another change established a new network upgrade reimbursement policy when the ISO is an “affected system.”

“In the last decade, there have been no instances where a generator’s interconnection to a neighboring balancing authority area affected the reliability of the ISO grid such that network upgrades were required,” Millar’s memo said. “In interconnection terms, the ISO is almost never an “affected system,” and has only been asked to perform affected system studies a handful of times. Most of these studies were not performed because the project quickly withdrew.

“However, recently the ISO has received a few notices from neighboring areas that a proposed interconnection potentially may affect the ISO and could warrant ISO study,” it said. “Although the probability is very remote that an external interconnection would require network upgrades on the ISO system, Management believes the ISO tariff should have a clear policy on this issue.”

The changes still require FERC approval.

Other enhancements do not require tariff changes or board approval, such as making data more easily accessible and publicly available to help developers determine the best locations to connect new resources and to better understand the status of projects in queue.

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SPP Board Bypasses Stakeholders on PRM Obligation Exemptions

SPP’s Board of Directors has given its state regulators the go-ahead to file a proposed tariff change that would allow load-responsible entities (LREs) to qualify for and receive exemptions from deficiency payments for not meeting their planning reserve margin (PRM) requirements.

Under the RTO’s tariff, the Regional State Committee has the authority to direct staff to file changes with FERC without the board’s approval. SPP’s directors yielded to the RSC on Oct. 25 by authorizing the filing after the committee’s earlier approval of the revision requests (RR 515).

In doing so, the board disappointed stakeholders who had approved a slightly different version of RR515 brought forward by the Supply Adequacy Working Group (SAWG) two weeks earlier. (See “Members Address Resource Adequacy,” SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)

Speaking for the stakeholders she represents as the Markets and Operations Policy Committee’s chair, Evergy’s Denise Buffington said she expects the waiver process to fail at FERC.

“Not because of the substance of the process, but because it is likely to be protested by SPP stakeholders,” she told the board last week. “This gives FERC an easy path to deny something that is hard. I believe they’ll do that because, first of all, they don’t like granting waivers. So, if we are not in lockstep about what the waiver looks like and the criteria and all … the easy thing for FERC to do is to say, ‘There is no waiver.’ So essentially, the results of the decision that was made yesterday means that more responsible entities are likely not to have an option of a waiver.”

Several members suggested SPP’s stakeholders should ensure that important issues are vetted appropriately. Board Chair Larry Altenbaumer agreed, saying, “This is a tough issue because it tends to be a bifurcated issue.

“There are certain responsibilities that are vested with the RSC. This is one of them. And I think the RSC has the full authority to determine how they want to reach their decisions,” Altenbaumer said. “Where I sit as a board member, I think we all strive and desire and try to help facilitate reaching consensus and alignment among our stakeholders. My view is that what we are attempting to do here is to try to reengage the stakeholder process to see if we can now come up with something that might be a balanced outcome.

“I think in the final analysis, the board has to act independently,” he added.

The RSC approved a version proposed by its Cost Allocation Working Group and tweaked by the Market Monitoring Unit. It calls for up to a two-year exemption from deficiency payments, whereas the MOPC version allows a three-year exemption. The CAWG proposal also requires LREs to meet two tests to claim the waiver, while MOPC’s only required complying with one of the two.

LREs would qualify for the waiver in both versions by demonstrating they have enough capacity to meet forecasted load for the upcoming season and the prior effective PRM. Under the CAWG version, they must also prove by a certain date each year that sufficient capacity for purchase has not been identified on a virtual bulletin board; they have a contracted obligation to purchase capacity; and they have a pending request for enough interim, surplus or replacement generator interconnection service to provide planning reserves to SPP.

During a closed-door education session for the RSC on Oct. 24 before its regular meeting, the MMU presented its revisions to the CAWG proposal that included extending the deadline for waiver exemptions from March 10 to May 1 and allowing LREs to cure at least a portion of their deficiency, thus reducing the penalty. The RSC accepted both suggestions.

Buffington protested the lack of stakeholder input into the MMU’s recommendations. RSC President Randy Christmann, a member of North Dakota’s Public Service Commission, countered by telling the board that the assertion that the MMU’s changes were never brought to MOPC “almost makes it sound like it was some surprise thing that was brought on the membership yesterday.”

“Well, the fact of the matter is I studied it up in North Dakota and learned about it, and multiple other states did as well, and I’m confident that companies are aware of those postings,” Christmann said.

The board in July approved an increase to the RTO’s planning reserve margin from 12% to 15%, effective next year. MOPC had recommended a “stair-step” increase by adding a percentage point to the PRM over three successive years. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

Stakeholders have said they support an adequate PRM, but that the sudden 25% increase has left them with just a few months to acquire significant enough capacity to meet contractual obligations. Some also complained that not enough excess capacity is available for purchase.

“People have been ghosted. … They’ve been offered capacity, but then it’s pulled back,” Golden Spread Electric Cooperative’s Natasha Henderson, the SAWG’s chair, told the RSC. “It’s pulled back because of the uncertainty that we’re dealing with [over] what’s the right policy.”

Several state regulators expressed concern that the stakeholder process had not reached full consensus. However, they approved the modified CAWG version by a 9-3 margin. Kansas’ Andrew French, Oklahoma’s Dana Murphy and Texas’ Will McAdams all voted against the measure.

“Everything I’ve heard this week is that we have more time to explore this. We’ve had these issues in the past where people want to continue debating … I don’t feel like we’re right there yet,” French said. “My biggest concern is, have we really run this down to the best solution it can be? This will be in the tariff. … It’s going to be the process moving forward.”

Evergy, Golden Spread, Liberty Utilities, Oklahoma Municipal Power Authority, Public Service Company of Oklahoma and Southwestern Public Service were the only representatives of the 22-person Members Committee to vote against authorizing RR515’s filing.

A virtual bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU able to review the data.

SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year).