The Washington Fish and Wildlife Commission last month unanimously downgraded the status of ferruginous hawks from threatened to endangered.
Climate change and wind turbines were two of several factors contributing to that decision.
Whileferruginous hawksare not listed as a threatened or endangered species by the federal government, they are listed for protection by the state of Washington.
The species has struggled in Washington because of a shrinking prey population, habitat encroachment by expanding agriculture, deaths from wind turbine strikes and wildfire destruction of nesting areas. The ferruginous hawks spend five months a year in the state when they nest from April through the summer; they migrate elsewhere in the Western U.S. for the other seven months.
The birds are among the nation’s largest hawks with average wingspans of 56 inches. They live in grasslands and shrub steppes, which are found extensively in south-central and southeastern Washington. Shrub steppe is a mostly treeless semi-desert filled with sagebrush and a complicated ecosystem at ground level.
The Washington Department of Fish and Wildlife (WDFW) tallied 55 nesting pairs of hawks in 1995 and 32 pairs in 2016, according to an August 2021 department report to the commission. About 60% of the nesting pairs are found in Washington’s Benton and Franklin counties.
The continent’s biggest nesting area is in Alberta, Canada, where ferruginous hawk populations have not been hit as hard.
Washington reviews the status of its sensitive species every five years, and 2021 is when the ferruginous hawks’ routine review was scheduled.
The August report by the WDFW pointed to climate change as one reason to downgrade the hawk population to endangered.
An Audubon computer modeling study concluded that a 1.5-degree Celsius increase in average temperature will trim ferruginous hawk habitats by 18% in the West, including part of southeastern Washington. A 2-degree increase would trim that habitat by 28%, the same modeling showed, while an increase of 3 degrees would translate into a loss of 58% of nesting areas.
Increasing temperatures and uncertainty about trends in rainfall are expected to lead to more grass fires in the shrub steppe habitats favored by the hawks, while harming the birds’ chief prey — ground squirrels, jackrabbits and prairie dogs, the report said. Ferruginous hawks tend to focus on a few specific species, such as ground squirrels, as prey and are reluctant to expand their diets, James Watson, a WDFW researcher, and one of the August report’s authors, told NetZero Insider.
Watson said eight ferruginous hawks have been killed by Washington wind turbines since 2001. A major wind project with 224 turbines has been proposed for shrub-steppe land in Benton County’s Horse Heaven Hills — land frequented by ferruginous hawks.
“Wind turbines are one of many types of fatalities. But they’re not the main reason” for the downgrade, WDFW habitat biologist Michael Ritter said. He noted expansion of agricultural land is a huge factor in the shrinking habitat and in the decision to declare the hawks endangered.
More than half of Washington’s original shrub steppe has been taken over by agriculture, according to the WDFW.
Watson said other states should keep an eye on the factors that led to the wildlife commission’s August decision. “This is a harbinger of things to come in other places,” he said.
Stakeholders endorsed PJM’s proposal to change the undefined regulation mileage ratio calculation after several months of debate over what number to use in the calculation.
PJM’s proposal, which called for setting the RegA dispatch mileage floor at 0.1 instead of zero, was endorsed with 152 votes in favor (64%) at last week’s Market Implementation Committee meeting. In a vote asking if stakeholders supported the PJM proposal over the status quo, the plan was endorsed with 147 votes in favor (67%).
Members had originally delayed adopting the RegA dispatch after a unanimous vote to amend PJM’s issue charge at the July MIC meeting, requesting to remove the suggested “quick fix” process from the proposal and instead handle discussions under an abbreviated consensus-based issues resolution process. (See “Regulation Mileage Ratio Delayed,” PJM MIC Briefs: July 14, 2021.)
PJM originally sought to work the issue through the quick-fix process in Manual 34 and take final votes at the July Operating Committee, Markets and Reliability Committee and Members Committee meetings. But several stakeholders challenged the proposed solution of updating values in the regulation mileage ratio, saying it was too complicated to address through the quick-fix process. (See “Regulation Mileage Ratio First Read,” PJM MRC/MC Briefs: June 23, 2021.)
Instances of RegA hourly mileage rates less than 0.1 in PJM since 2013 | PJM
Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the RTO’s proposed solution. Olaleye said PJM had not received any additional feedback from stakeholders since the issue was discussed at the August MIC meeting, and no changes had been made to the proposal.
Regulation mileage is the measurement of the amount of movement requested by the regulation control signal that a resource is following; it is calculated for the duration of the operating hour for each regulation control signal. PJM’s performance-based regulation market splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units that operate for shorter periods, including batteries. If a signal is “pegged” high or low for an entire operating hour, the corresponding mileage would be zero for that hour.
Olaleye said PJM has seen an increased frequency of RegA signal pegging and times the RegA signal is pegged for extended periods, highlighting a potential problem in the regulation mileage ratio calculation. The RegA mileage can be set at zero for a given hour and create a divide-by-zero error in the calculation of the mileage ratio.
PJM proposed setting the RegA mileage floor at 0.1 instead of zero, Olaleye said, which would allow for a “valid solution” for the ratio and still maintain market design objectives. He said the change would have no impact on the regulation signal design, operations or regulation market clearing.
Independent Market Monitor Joe Bowring presented a counterproposal, questioning PJM’s use of the 0.1 value. The IMM proposed a cap of 5.5 on the realized mileage ratio in all hours, indicating the cap would eliminate the current undefined mileage ratio result that PJM is attempting to address.
Bowring said the 5.5 cap would reduce but not eliminate the market distortion resulting from the use of mileage ratios when they incorrectly represent regulation output and that the change would affect less than 50% of impacted hours based on data collected by the IMM over the last 15 months.
Stakeholders ultimately rejected the IMM proposal, with 129 members voting against adoption (56%).
Gary Greiner, director of market policy for Public Service Enterprise Group, said the IMM’s proposal was “a lot more comprehensive,” and the solution suggested that there’s a problem with the way that the mileage ratio works. Greiner said it seemed the quick fix path was “not the right path to go down” if the problems are as comprehensive as the IMM’s proposal indicates.
Greiner said the divide-by-zero error could be solved “pretty easily without a lot of impact” by adopting PJM’s 0.1 proposal and come back with a more extensive stakeholder process in the future to address the milage ratio issues brought up by the IMM.
RPM Capacity Transfer Rights Rejected
A proposal by Buckeye Power to address the allocation of capacity transfer rights (CTRs) failed to win stakeholder approval.
Members rejected the proposal worked on for the last six months in the MIC, with only 55 voting in support (28%). Stakeholders originally endorsed Buckeye’s issue charge at the March MIC meeting with 79% support. (See “RPM Issue Charge Endorsed,” PJM MIC Briefs: March 10, 2021.)
Kevin Zemanek, director of system operations for Buckeye Power, reviewed Buckeye’s proposal regarding the allocation of CTRs, saying under the Reliability Pricing Model (RPM), CTRs return to load-serving entities (LSEs) capacity market congestion revenues that occur when there’s a difference between the prices paid by load and market revenue received by cleared resources. CTRs permit LSEs with load inside a constrained locational delivery area (LDA) to receive a credit for the import of capacity from a lower-priced region. (See “RPM Capacity Transfer Rights,” PJM MIC Briefs: Aug. 11, 2021.)
PJM does not have a way to allocate CTRs directly to an LSE with network resources outside a constrained LDA but whose resources have been designed as deliverable on the LSE’s network integration transmission service agreement. Instead, Zemanek said, PJM allocates CTRs pro rata to each LSE serving load in the LDA or zone based on the LSE’s share of the zonal unforced capacity obligation.
Buckeye’s proposal called for first allocating zonal CTRs to LSEs with historic generation resources identified as network resources in a network integration transmission service agreement (NITSA). The allocated CTRs will be “sufficient to meet the LSE’s daily unforced capacity (UCAP) load obligation but shall not exceed the total amount of the LSE’s generation capacity as identified on the LSE’s NITSA.”
Buckeye said the impact of the current rules vary from year to year; it said the rules cost it $10 million in the 2015/16 delivery year and $2.5 million in 2016/17.
The proposal would have recognized generation resources and transmission rights that existed prior to the implementation of RPM but would also terminate upon the retirement of a resource or a change in the designated resource status in the NITSA.
“These are not evergreen and would not last forever,” Zemanek said. “Based on the historical situations, we think this is minimal impact.”
Bowring said the IMM believes it’s inconsistent to use prior contracts to calculate network congestion. The current CTR process “certainly needs to be revisited” in the review of the PJM capacity market, he said, but it wasn’t appropriate to reevaluate it on a “one-off basis” with Buckeye.
“To the extent Buckeye is paid more, others will be paid less,” Bowring said. “And we don’t agree that there’s been any detailed analysis of what the ultimate impact will be.”
Peak Shaving Plan
Ed Rich, senior analyst with PJM’s capacity market operations, provided a first read of the problem statement, issue charge and solution addressing the peak shaving adjustment shortfall calculation in attachment D of Manual 19 through the “quick fix” process.
Rich said the peak shaving performance rating is used to correct the impact of approved peak shaving programs in the load forecast to be consistent with how the programs have performed when required to reduce load.
The current documented calculation for the megawatt shortfall in Manual 19 says, “For each hour of a required peak shaving event, a shortfall value is calculated as the aggregated metered load of all participants minus their aggregated customer baseline (CBL).” Rich said PJM has determined that the calculation is “erroneous” since “taking the difference of the metered load and the customer baseline will only calculate a shortfall value when a resource does not reduce but has a greater metered load than the customer baseline.”
Rich said PJM is proposing to change the shortfall value calculation as the “resource’s total participating megawatt minus the difference of their customer baseline (CBL) minus their metered load adjusted for line losses, capped at zero.”
Rich said the issue found by PJM has caused no incorrect shortfalls to be calculated because no peak shaving plans have been submitted and cleared in a capacity auction since the program was created.
“Instead of taking the average shortfall per event, using the total calculations for the year would be a more accurate representation of their total performance rating,” Rich said.
Bowring said he was a “little surprised” PJM was putting the issue through the quick fix process given that the key work activities and scope include providing background education on the issue. He said the issue could use more stakeholder discussion to grasp the concepts being changed.
Stakeholders unanimously endorsed manual changes regarding the incremental and no-load energy offers.
Tom Hauske of PJM’s performance compliance department reviewed the Manual 15: Cost Development Guidelines revisions regarding the incremental and no-load energy offer developed in the Cost Development Subcommittee (CDS). Hauske first introduced the revisions at the August MIC meeting. (See “Manual 15 Revisions,” PJM MIC Briefs: Aug. 11, 2021.)
“There are a lot of wholesale changes in Manual 15,” Hauske said.
The most significant manual changes came in section 2.3 for the definition of incremental energy cost, Hauske said, which states, “The incremental energy cost is the cost in dollars per MWh of providing an additional MWh from a synchronized unit.” The changes also include methods for market sellers to submit sloped, stepped or block loaded incremental offers into PJM’s Markets Gateway System.
The manual changes will go to the MRC for endorsement.
Energy Scheduling Practices Revisions Endorsed
Members unanimously endorsed revisions to the Regional Transmission and Energy Scheduling Practices document.
Chris Pacella, senior lead analyst in PJM’s transmission service department, provided an overview of the revisions. Pacella said the revisions consisted of three main drivers, including minor clarifications related to process improvements in the 2019 OASIS Refresh project, minor updates as part of a general review, and updates related to the North American Energy Standards Board’s Wholesale Electric Quadrant v3.2 Business Practice Standards that take effect Oct. 27.
PJM is asking FERC to delay the Base Residual Auction for the 2023/24 delivery year by almost two months, citing the commission’s Sept. 2 order revising the RTO’s market seller offer cap (MSOC).
In a compliance filing Friday, PJM recommended delaying the start of the 2023/24 BRA by 55 days, from Dec. 1 until Jan. 25, 2022 and the 2023/24 third incremental auction from Feb. 27, 2023 to March 21, 2023 (ER21-2877). The filing also seeks to change the starts of subsequent Reliability Pricing Model (RPM) auctions, moving the 2024/25 BRA from June 15, 2022 to Aug. 9, 2022; the 2025/26 BRA from Jan. 4, 2023 to Feb. 28, 2023, and the 2026/27 BRA from March 17, 2023 to Aug. 29, 2023.
PJM said changing the dates of the RPM auctions is necessary to maintain the six-and-a-half-month gap between auctions so that market participants “have sufficient time to review the results of each auction before deciding whether to continue offering a resource in the subsequent auction.”PJM’s updated RPM auction schedule through the 2026/27 delivery years. | PJM
The RTO said its request was prompted by FERC’s Sept. 2 order adopting the Independent Market Monitor’s unit-specific avoidable cost rate (ACR) proposal and requiring PJM to revise its tariff (EL19-47, EL19-63, ER21-2444). The Monitor’s proposal followed FERC’s March order requiring PJM to revise the MSOC to prevent sellers from exercising market power in the capacity market. (See FERC Backs PJM IMM on Market Power Claim.)The RTO said the auction delay was necessary to give capacity market sellers and the Monitor a “realistic opportunity” to appeal the RTO’s final decisions on unit-specific offer cap requests resulting from the MSOC rules change.
“PJM does not make the decision to seek a further delay of the already delayed upcoming BRA lightly,” the RTO said in its filing. “PJM strongly believes the three-year forward nature of the capacity auctions is a critically important feature of the Reliability Pricing Model construct and would prefer to expeditiously conduct the upcoming auctions without delay. At the same time, however, given the expected volume of unit-specific requests stemming from the significant change to the MSOC rules, PJM believes that a revised timeframe must be established to allow for an orderly and complete Market Monitor and PJM review of all such requests.
Stakeholder Opinions
PJM received mixed feedback on the proposed delay at last week’s Market Implementation Committee meeting.
Chen Lu of PJM provided an overview of the capacity MSOC order, while Pete Langbein, manager of PJM’s demand side response operations, presented the draft timelines for the pre-auction activities for the upcoming BRA impacted by the order and the timing of the auction.
Langbein said PJM attempted to focus the timeline changes on the pre-auction tasks and activities that were “clear and transparent” to avoid stakeholder confusion. Langbein said the RTO was searching for a way so stakeholders would have a “reasonable amount of time” to finish their activities for the auction.
“The BRA auction and the associated timeline is pretty complicated, and there are a lot of dependencies between the different activities,” Langbein said. “There’s a bit of a dance to make all these different dates work.”
Paul Sotkiewicz of E-Cubed Policy Associates said he thought it would be better for his clients to have PJM compress the timeframe and “keep the auctions moving on time.”
Jason Barker of Exelon said he appreciated PJM’s attempt to balance the “orderly administration of the auction” by proposing a delay. But Barker said Exelon “tilted towards” the idea of keeping the December auction on schedule and that one of the company’s biggest concerns with changing dates was the possibility of having to redo any ACR submittals that had already been submitted.
Market Monitor Joe Bowring said that, without a delay, generation owners would have eight days to complete their ACR filings, which would be “close to impossible” for anyone having to make new ACR submittals.
“We all like to live in a completely certain world with certain deadlines, but that’s not where we are,” Bowring said, adding that PJM is “likely to see some more uncertainty” in the capacity auctions when the minimum offer price rule (MOPR) order is finally decided.
Jim Benchek of FirstEnergy said he would “urge” PJM to file the delayed schedule. Benchek said if a market seller didn’t anticipate having to go through the unit-specific net ACR calculation process, completing the process in eight days is “almost an impossible amount of time.”
“You need to afford market sellers the right amount of time to do things thoroughly and correctly,” Benchek said.
Langbein said no matter what timeline is ultimately approved by FERC, the process is going to be new for many stakeholders and will create a large volume of requests.
“We do not believe this is something administrative that’s going to be easy to do,” Langbein said.
MSOC Order
In March, the commission ordered PJM to revise its MSOC, siding with arguments made in separate complaints filed in 2019 by the IMM and several consumer advocate groups that challenged the RTO’s Capacity Performance (CP) assumptions and arguing the existing rules were allowing sellers to exercise market power.
In August 2018, the Monitor concluded that PJM ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of “economic withholding” encouraged by the inflated MSOC. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)
Unit-specific MSOCs are to be based on avoidable costs and the opportunity cost of taking on a CP obligation, the Monitor said, including expectations of bonus payments or penalties for performance during an emergency. The timespan for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAI) in compliance with FERC Order 825 in 2018.
A PAI is triggered when PJM determines a supply reliability issue exists, providing credits for generators that overperform their capacity commitments and penalties for those who underperform.
The Monitor originally suggested using 60 PAIs or five PAHs — compared with the current 360 PAIs/30 PAHs — in calculating a more appropriate seller cap.
FERC ordered PJM and its stakeholders to determine a suitable replacement rate within 45 days of the filing in March, addressing the “appropriateness of using different values” for penalty PAI and expected PAI in the default CP MSOC calculation and a method for setting each value.
Ultimately the IMM’s unit-specific ACR proposal filed on April 28 won out over three other proposals submitted to the commission.
The unit-specific ACR proposal said offers should be capped at the resource’s unit-specific net ACR, meaning “unit-specific gross ACR minus forward-looking net energy and ancillary service revenues, with the option to use the technology-specific default gross ACRs minus unit-specific forward-looking net energy and ancillary service revenues.” The Monitor said the commission recently accepted technology-specific default gross ACRs in the MOPR proceeding.
The IMM said its proposal would be a “return to the requirements prior to the introduction of CP, when offers were capped at unit-specific net ACR.” The Monitor said it already has experience with calculating unit-specific and default net ACR offer caps in the capacity market, and the process is “manageable from an administrative perspective” as the PJM tariff already includes a formula for the unit-specific gross ACR review.
FERC said the unit-specific ACR proposal was preferable to the three other options presented to the commission because it would “best ensure the capacity market’s overall competitiveness and enable the Market Monitor and PJM to sufficiently review and mitigate offers to prevent the exercise of market power.”
“We recognize that eliminating the default offer cap will likely create more work for the Market Monitor and sellers by requiring the individual review of a higher number of capacity offers,” the commission said in its order. “But we find that such review is reasonable and needed to address potential market power abuse in PJM. The other proposals would result in the review of fewer offers, and potentially not the marginal offer(s), and therefore be less effective at identifying and mitigating the exercise of market power in PJM.”
Commissioner James Danly dissented from the Sept. 2 order, saying it “risks over-mitigation.” Danly said fixing the default offer cap would be a “far better solution than the alternative supported by the majority,” which “jettisons” the offer cap for a “full unit-specific review of all offers above zero.”
Danly said the unit-specific review will give “extraordinarily broad new powers” to the IMM to “second guess” the judgment of market sellers. He said the commission will be the only “check” on the review powers of the Monitor and that FERC “should not be in the business of determining seller offers in advance of auctions.”
“There are problems with the current default offer cap, but unit-specific review of all resources is far too invasive a ‘remedy,’” Danly said. “It should be clear to anyone paying attention that PJM’s market design is becoming increasingly discriminatory against existing generators. It is swift becoming unduly so. And the more we redesign our markets into elaborate cost-justification exercises, the fewer of the benefits promised by markets can be realized.”
PJM Filing
Besides adopting the IMM’s proposal, FERC also accepted a waiver request filed by PJM in July regarding certain pre-auction deadlines in the event a lower value for the replacement default offer cap was established (ER21-2444).
In Friday’s filing, PJM said the potential volume of unit-specific requests stemming from the “significant change to the offer cap rules” necessitates establishing a new timeframe that “allows for orderly and complete IMM and PJM review of all such requests, and the ability for stakeholders to appeal PJM’s final decisions to the FERC prior to executing the auction.”
“There is simply no realistic scenario for PJM and the Market Monitor to review and make final unit-specific offer cap and must-offer determinations more than 60 days prior to the currently scheduled Dec. 1, 2021 BRA,” PJM said in its filing. “This modest delay will allow 60 days for capacity market sellers and the Market Monitor to seek remedies from the commission prior to the commencement of the next BRA. This is necessary and appropriate given PJM’s expectation that many capacity market sellers and/or the Market Monitor will inevitably disagree with the final unit-specific offer cap determinations. Indeed, based on the information currently available to PJM, none of the unit-specific offer caps requested to date under the existing pre-auction deadlines for the 2023/2024 BRA have been accepted by the Market Monitor.”
PJM’s proposal calls for new deadlines for capacity market sellers to submit a must-offer exception request associated with resource deactivations and a unit-specific offer cap, moving the current deadline dates of July 19 and Aug. 3 to Oct. 1. The RTO said the new deadlines provide market sellers three weeks to determine whether to seek a unit-specific offer cap and to prepare necessary supporting documentation.
“Consolidating the deadline for these submissions to the same date will save some time and allow PJM to conduct the upcoming BRA without significant additional delays,” the RTO said.
PJM also proposed to push back the deadline for the IMM to review and propose a recommendation on market sellers’ unit-specific offer cap and/or must-offer exception request associated with resource deactivations to Oct. 31. The RTO said the change will give the Monitor its usual 30-day period from the unit-specific offer cap and must-offer submission deadline to “review and provide its proposed recommendation of various unit-specific offer cap and must-offer exception requests.”
The schedule changes provide market sellers with five days to review the IMM’s recommendation and notify PJM and the Market Monitor whether it agrees with the unit-specific offer cap or must-offer exception associated with resource deactivations proposed by the Market Monitor.
PJM said it proposed to maintain the normal 25-day period for the RTO to make its final determination on disagreements in the unit-specific offer cap and/or must-offer exception requests, setting the date at Nov. 25 instead of Sept. 27.
“Capacity market sellers will all retain the opportunity to offer resources into the RPM auction sufficiently in advance of the delivery year even with this modest delay and resources that clear the auction will continue to receive capacity revenues during the delivery year,” PJM said.
PJM stakeholders unanimously endorsed manual updates related to behind-the-meter generation (BTMG) business rules on status changes developed in special sessions of the Market Implementation Committee.
Terri Esterly, senior lead engineer in PJM’s markets automation and quality assurance department, reviewed Manual 14D: Generator Operational Requirements updates to appendix A during last week’s Operating Committee meeting. Stakeholders endorsed related changes to Manual 14G at the Aug. 31 Planning Committee meeting. (See “Manual 14G Updates Endorsed,” PJM PC/TEAC Briefs: Aug. 31, 2021.)
Esterly said PJM made no changes to the updates since she first presented the manual changes at the August OC meeting. (See “Manual 14D Updates,” PJM Operating Committee Briefs: Aug. 12, 2021.)
The updates to Manual 14D were intended to address conflicts with the Reliability Pricing Model must-offer requirement and “removal from generation capacity resource status” business rules, Esterly said. Updates included addressing performance obligation impacts, clarifications to business rules regarding load impacts from status changes, and participation in PJM’s load response.
In a section on designating capability as a generation capacity resource and/or an energy resource, PJM added a business rule to make it clear a new service request must be submitted for the designation, Esterly said. Another rule was made to clarify the process to request a change from BTMG status to generation capacity resource status.
In the section on participation in PJM load response, Esterly said the RTO added the process to indicate that a BTMG unit is participating in PJM load response by providing on-site generator data.
The manual updates now go to the Sept. 29 Markets and Reliability Committee meeting for a first read and endorsement at the Oct. 20 MRC meeting.
Manual 01 Changes
A manual attachment created last year in the wake of COVID-19 emergency protocols is set to become permanent and changed to address other emergency situations.
Chris Moran, senior lead analyst with PJM’s NERC compliance team, provided a first read of updates to Manual 01 Attachment F: Control Center and Data Exchange Requirements regarding the RTO’s market operation centers being able to conduct remote operations.
Moran said attachment F of Manual 01 was originally developed and implemented at the start of the COVID-19 pandemic to provide guidance for remote operations “should imminent risk of COVID-19 start to affect staffing” in PJM’s market operation control centers. The temporary attachment, which became effective in April 2020, was set to expire on Dec. 31 of this year.
As the pandemic has progressed, Moran said, it has “become apparent” to PJM that attachment F needs to become a permanent part of Manual 01. Several stakeholders also had suggested making the attachment permanent at a previous OC meeting. (See “COVID-19 Update,” PJM Operating Committee Briefs: June 10, 2021.)
Moran said PJM wanted to make attachment F broader so that it doesn’t simply apply to COVID-19. The language changes include replacing COVID-19 with “exceptional circumstances,” which include severe weather, natural disasters, civil unrest and other pandemic events.
PJM’s definition for exceptional circumstance says, “an event or effect that can be neither anticipated nor controlled, including but not limited to any act of a public enemy, war, insurrection, riot, fire, severe weather, natural disaster, flood, civil unrest, explosion, pandemic or other public health emergency, as reasonably determined by PJM.”
The attachment changes also include updating NERC compliance contact information for PJM.
The OC will vote on the manual changes at its October meeting.
COVID-19 Update
Becky Carroll of PJM provided an update on the RTO’s response to COVID-19, saying staff is reviewing Occupational Health and Safety Administration rules regarding vaccinations recently announced by the Biden administration.
Carroll said PJM is “still evaluating” the new rules that would require vaccinations or a weekly negative COVID-19 test for any company over 100 employees. She said PJM will be communicating more details to its employees and stakeholders following consultation with the RTO’s legal counsel, its epidemiologist and the executive team.
“As we’re thinking about this new rule, we’ll be taking the safety and wellbeing of PJM staff into account, given that’s paramount,” Carroll said.
Some PJM stakeholders have been arguing for several months that the RTO should mandate vaccinations for all its employees. (See “COVID-19 Update,” PJM Operating Committee Briefs: Aug. 12, 2021.)
Ken Foladare of Tangibl Group said he understands that PJM must consult with its legal counsel over the regulations, but he said other large organizations already had mandated vaccines for their employees to come back to the office. Foladare said he found it “disappointing” that PJM had not taken similar measures to mandate vaccines.
Mike Bryson, PJM’s senior vice president of operations, said the RTO “continues to appreciate” the positions of stakeholders. Bryson said PJM CEO Manu Asthana has had discussions with senior leadership of member companies about their stance on vaccinations.
“We continue to evaluate the way our posture has been in the interest of protecting staff that has to come on campus,” Bryson said.
Adrien Ford of Old Dominion Electric Cooperative asked if there has been any change in PJM’s plan to have staff return to the Valley Forge campus given the rising cases of COVID-19. Staff were originally scheduled to start coming back to the campus by Sept. 1.
Carroll said PJM is evaluating the plan to return to campus “on a two-week basis” and have delayed the return until the middle of September. She said staff will receive another update on Sept. 13 to determine if they can return to campus or delay it for another two weeks.
“We are going to continue to evaluate on a two-week cycle,” Carroll said.
Developers of new wind and solar projects in MISO’s and SPP’s generator interconnection queues are being asked to foot nearly the entire bill when connecting to the grid, while the entire system typically benefits from significant transmission upgrades, according to an ICF Resources report released Thursday by the American Council on Renewable Energy.
ICF, a global consulting services company, said its modeling of recent network upgrades assigned to the RTOs’ new wind and solar projects found that many of these upgrades, if built, would deliver significant benefits to the grid. “The cost allocation fails to consider potential regional economic benefits from these network upgrades,” the authors wrote.
“This report confirms what many people have long believed: that network upgrades required of interconnecting generators often provide broader system benefits, even though the cost of the upgrades falls on the developers,” former FERC Chair Norman Bay, now a partner with Willkie Farr & Gallagher, said during a press event Thursday organized by ACORE.
The report, “Just and Reasonable? Transmission Upgrades Charged to Interconnecting Generators Are Delivering System-Wide Benefits,” says the RTOs’ most recent system impact studies show network upgrade costs in the range of $270 (MISO South) to $448/kW (SPP).
MISO’s most recent definitive planning phase (DPP) study for its generator interconnection queue found nearly $2.5 billion worth of upgrades were needed to interconnect 9.2 GW of generation in MISO South, according to ICF. Similarly, SPP’s most recent definitive interconnection system impact study (DISIS) identified more than $4.6 billion worth of network upgrades to help interconnect 10.4 GW of generation.
The study’s 12 short-listed projects in MISO and SPP. | ACORE“Given the over-subscribed power grid, interconnection customers are being allocated the full cost of adding new lanes to the highway and are increasingly responsible for building new highways,” the authors wrote.
Under current cost allocation rules, project developers in both regions are responsible for paying for nearly all the upgrades’ costs, potentially violating the “beneficiary pays” principle and the Federal Power Act’s “just and reasonable” requirements. Under FERC’s “beneficiary pays” principle, RTOs are required to ensure that transmission costs are assigned at least “roughly commensurate with estimated benefits.”
The costs are assigned directly to generators in SPP. In MISO, generators are responsible for 90% of the cost for upgrades 345 kV and higher, with 10% allocated regionally. Those below the threshold pay 100%.
“At the end of the day, our customers are bearing the costs of the projects that we’re selling to them,” Matt Pawlowski, NextEra Energy’s executive director of business management and regulatory affairs, said Thursday. “If a significant amount of the upgrade costs is borne on us, we’re passing those on to the customer. Whether it’s a corporation or the ultimate end user of a utility, the ratepayers end up paying for that.”
Pawlowski and Caroline Golin, head of energy markets and policy for Google, both called for a change in RTOs’ planning practices, saying they no longer match a system that is flush with renewable energy projects.
“I think we’re being foolish if we don’t recognize we need to massively overhaul our transmission planning system. That starts with a general recognition that we are throwing money out the door by not doing that, and we are harming our community and the [renewable] industry,” Golin said.
Matt Pawlowski, NextEra Energy | SPPRenewable generation interconnection requests have risen exponentially in both MISO and SPP as wind and solar energy prices have continued to decline and states and corporate buyers seek to meet their renewable standards and goals. MISO and SPP have more than 150 GW of active solar, wind and hybrid resources stuck in their interconnection queues across both markets. At the time of the study, 92% of the 79 GW of requests in MISO’s queue and 95% of the 103 GW of requests in SPP’s queue were from those resources.
FERC is considering whether to re-evaluate how grid operators allocate costs for new projects seeking to connect to the grid. In July, the commission opened an Advanced Notice of Proposed Rulemaking (RM21-17) to reconsider its transmission planning, cost allocation and interconnection rules. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)
Bay called the ANOPR “timely.”
“The big tension seems to be between two principles at FERC,” he said. “On the one hand, cost causation, and on the other hand, beneficiary pays. This study shows in many instances, the beneficiary-pays principle in RTO markets is not being fully followed. This, in turn, creates a classic free-rider problem and may result in undue burden being imposed upon developers.”
SPP did not respond to the report by press time. A MISO spokesperson said the RTO is focused on its long-range transmission planning initiative and it has not reviewed the study. The grid operator has repeatedly said the plan will support the changing resource mix. (See MISO Targets March Approval for Long-term Tx Projects.)
Both RTOs are currently engaged in a joint effort to find interregional transmission projects that can help ease their crowded interconnection queues. (See MISO, SPP Offer Idea on Joint Interconnection Tx Allocation.) SPP is also involved in several initiatives to consolidate and improve its own planning process.
ICF worked closely with staff in both regions in developing the assumptions and modeling used in the report, which it produced for ACORE and its Macro Grid Initiative and American Clean Power Association collaborators.
The analysts used “very conservative” assumptions in evaluating the economic benefits of a representative sample of upgrade projects assigned through the MISO and SPP interconnection processes over the last seven years. They screened nearly 230 upgrades spanning four SPP DISIS studies (2014-2017) and 433 network upgrades covering four MISO DPP studies (2016-2020) in shortlisting six network upgrades in each RTO.
Ten of the study’s 12 network upgrades provided positive adjusted production cost benefits.
The study design, including screening process and criteria to shortlist, was shared with both RTOs’ staffs. The final set of shortlisted network upgrades was made after consultation with MISO and SPP.
SPP staff and stakeholders last week discussed high-level recommendations for consolidating the RTO’s transmission planning processes, an initiative the RTO says could save $9 million annually by 2030 while also producing a more holistic view of its transmission needs.
“I think there’s even more value to be gained from this,” predicted SPP COO Lanny Nickell, who said a business case that “fleshes that out” is being developed.
“By consolidating the processes and trying to meet all the needs with single study process — whether it’s new generation that want to be interconnected or load growth — we believe there’s a lot of value to be gained by deriving the optimal transmission set … in more equitable fashion than today,” Nickell said.
During an education session Wednesday, Nickell told the Markets and Operations Policy Committee that SPP’s current planning processes cost about $28.5 million annually, but that the new consolidated process is projected to cost $25.5 million during its first three years and $24.7 million in Year 4 and beyond. Savings are expected to reach up to $8.9 million by 2030.
Staff currently spends more than 132,000 hours annually in the planning processes, a number that is projected to drop by nearly 14,000 hours with consolidation. Nickell said it will take two to three years and $7.5 million to implement the consolidated approach.
The Strategic Planning Committee last year created the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT) to analyze the RTO’s interconnected planning processes and applicable cost-allocation methods. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020.)
The SCRIPT created six sub-teams, comprised of its members and SPP staff, to focus on consolidation, services, optimization, decision quality, transfers and cost-sharing. They have produced 48 recommendations and sub-recommendations over more than 60 meetings and 11 months. The SCRIPT has provided feedback on the recommendations, which are under review and likely to change.
Nickell said the team is nearing the end of its policy development and plans to share its results and a final version of its draft report during the October governance meetings.
“We do have some work ahead of us,” he said. “There’s going be another group of recommendations that will enable more benefits from having a consolidated process.”
The sub-team working toward an “appropriate consolidation” of SPP’s Integrated Transmission Planning (ITP), generator-interconnection and transmission service studies, is central to SCRIPT’s success. It recommended:
creating a common base model set to meet regional planning needs required by SPP’s Tariff and NERC reliability standards;
modifying the high-priority study planning assessment requirements to provide additional scope flexibility and allowing it to be performed on an as-needed basis;
expanding the model data systems used for collection and review, and developing automation and an intermediary database with links to existing regional planning tools to better correlate input data, processes and study outcomes; and
staff and stakeholders work together to evaluate, approve and build out design- and implementation-level processes for one of the two consolidated options for customer optionality, cost-certainty of assigned upgrades, and regulatory planning compliance.
The team’s two-phase approach involves first consolidating ITP, GI, transmission service, NERC transmission planning, and local planned transmission system changes processes. That would be followed by combining system load, sponsored upgrades, and generator retirement processes.
“We are going to be bound by NERC requirements to some degree. We’re going to have to keep some studies on track,” SPP’s Kelsey Allen said.
Allen said staff is considering providing “fast-track” options to quickly connect resources. “We’re hoping to be able to create a lot more efficiency in the processes than we have today, and that comes from the first consolidation,” he said.
Antoine Lucas, SPP’s engineering vice president, said his optimization sub-team recommendation that SPP develop a process to conduct holistic planning needs and solutions assessments complements the consolidation recommendations.
“It gives guidance on the approach and how to do that,” he said. “This really is all about identifying the projects that provide the most value to the overall region, but that also bolster the reliability expectation we have.”
Under the recommendation, staff would assess proposals for addressing market efficiency, public policy needs, and reliability issues for network load service and GI requests. Once the portfolio is established, staff could then conduct an impact analysis of GI requests and applicable transmission service requests impacts and use the results as a component of cost-sharing considerations.
“The fact [is we] don’t know what’s going to come out of the planning process. We do believe we can increase the value of transmission portfolios that are being recommended and approved,” Nickell said.
The Generator Outage Task Force (GOTF) also briefed MOPC during the education session on its work to address outage-scheduling practices and concerns over how to reliably schedule outages given the changing resource mix.
The task force was created after SPP declared a Level 1 energy emergency alert and it called for conservative operations 10 times in 2019. The grid operator attributed six of the 10 operations events to generation outages.
The group is recommending a generation assessment process that includes a long-term horizon (five years) and a short-term view (the next seven days). The assessment’s wind, demand, capacity and outage, and forced unscheduled outages will serve as inputs to determine the number of maintenance outages that can be taken without threatening reliability.
The GOTF is also urging SPP to change the outage/derate reporting threshold from 25 MW to 10 MW and to allow forced outages to have up to seven days of maximum lead time, so that they align with NERC’s generating availability data system.
The recommendations will be finalized during the task force’s next meeting Sept. 24.
A horde of solar developers want to set up projects in Eastern Washington, but the majority don’t appear to be doing their research early enough on the sensitive shrub steppe habitat that is prime turf for solar farms.
That is what the Habitat Committee of the state’s Fish and Wildlife Commission learned Tuesday.
The lack of attention is important because most of the proposed solar farms in Washington have targeted shrub steppe land east of the Cascade Mountains. Shrub steppe is a mostly treeless semi-desert filled with sagebrush that is home to several species of birds and mammals that are watching their habitats shrink. These include sage grouse, sharp-tailed grouse and pygmy rabbits.
Wildfires, agricultural fields and expanding cities and towns have chewed into the state’s original 10.4 million acres of shrub steppe, trimming it to 40% of its original size. Solar farms will further encroach on the remaining shrub steppe, Michael Ritter, a Washington Department of Fish and Wildlife (WDFW) habitat biologist told the committee.
Washington has 37 solar farms in operation, being built or on the drawing board, Ritter said. Thirty-five are east of the Cascades in or next to shrub-steppe lands; only two are west of the mountain range.
So far, only one of the eastern solar farms is operational, while two are being constructed and four are going through state permitting processes. Another 28 are on the drawing board, taking care of the homework needed before tackling the permitting processes, Ritter said. It usually takes one to two years of preliminary work before a solar project is ready to be unveiled, he added.
“These projects are already doing a lot of work in the background,” he said.
WDFW staff and Habitat Committee members voiced concern about solar developers neglecting to investigate sensitive species and habitat issues prior to locking themselves in to specific sites.
“There is a big public sense that these companies … will get a bit of a free pass [in getting their projects approved],” said committee member Molly Linville, a rancher and farmer in central Washington’s Douglas County.
Ritter said, “They ask me how to mitigate for the sage grouse. There is no mitigation. You don’t build there. … It’s like they think when they get into the permitting process, it’s going to happen. We may tweak it a little bit, but it’s going to get in. That’s too late. I wish the companies would reach out to us first.”
Linville noted that plans for three solar projects have recently appeared in Douglas County. None are far enough along to apply for permits, and none have researched habitat issues. She found out about them through news reports and the local grapevines.
Committee members said something must be done to get developers to inquire about sensitive habitat issues early in their brainstorming.
“We shouldn’t be put in the position of having to defend against green energy with our conservation needs. …. It’s a no-win situation,” said committee member Barbara Baker, an Olympia attorney.
The full commission is scheduled to discuss the matter on Sept 17.
Speaking on a panel at the quarterly meeting of ISO-NE’s Consumer Liaison Group on Thursday, the always outspoken Tyson Slocum, director of Public Citizen’s energy and climate program, did not mince words.
For more than 20 years, ISO-NE and NEPOOL have “essentially privatized public policymaking as private entities” through their respective administrations of the New England electric grid and stakeholder process, Slocum said. “There is inadequate transparency and accountability in these institutions that don’t reflect the public interest nature of what they’re doing.”
The Consumer Liaison Group holds open public forums to help regional consumers understand what is happening at the RTO. Slocum told it that “sweeping” reforms are needed to improve transparency and accountability. Neither ISO-NE Board of Directors nor NEPOOL stakeholder meetings are open to the public.
Opening NEPOOL stakeholder meetings to the interested public, plus recording and transcribing them, would be a start. It should be followed by a responsive ISO-NE board and reorientation of the NEPOOL voting sectors to make it less than “totally utility centric.” Currently, stakeholders are broken into six weighted sectors: Generation, Transmission, Supplier, Alternative Resources, Publicly Owned Entity and End User.
“This has no realistic application to all of the people that are actually impacted by our electricity system,” Slocum said.
Echoing Slocum’s call for changes, Jolette Westbrook, director and senior attorney for energy markets and regulation at the Environmental Defense Fund, said there is one significant barrier for most people needed to be eliminated: the cost of participation. NEPOOL membership fees range from $500 for End Users to $5,000 for Generation, Transmission and Supplier members.
“I’m sorry, we just have to realize that what one entity can afford may not be affordable to others,” Westbrook said.
Rebecca Tepper, chief of the Energy and Telecommunications Division in the Massachusetts Attorney General’s Office, said that although ISO-NE’s budget comes from collecting fees from market participants and ratepayers, “nobody seems to question the fact that we’re spending millions of dollars to have the utilities participate in these proceedings and customers pay for that.”
Tepper noted that governance of ISO-NE was one of the areas that the New England States Committee on Electricity identified in its vision statement in October 2020. In the follow-up report to the region’s governors in June, NESCOE noted that the agendas of ISO-NE board meetings “indicate governance and transparency discussion; however, no process has been convened or proposal advanced” with the states.
“One of the three things that the states had requested is the one that has not made much progress, or at least not to the outside world,” Tepper said. “I think it would be good to see that move forward and have some real dialogue about how the governance process can be more accommodating to people.”
Slocum said that a multistate RTO like ISO-NE faces different governance challenges than single-state grid operators, like CAISO and NYISO. Still, there are lessons to learn, especially with appointments to the board. CAISO had a similar board structure to ISO-NE until the Western energy crisis spurred the California State Legislature to give the governor power to appoint or remove CAISO board members.
“It’s a little more challenging to replicate that in New England, but it’s important to state that [CAISO] is seen as an active partner with the state’s ambitious climate and clean energy goals,” Slocum said.
There is often conflict between New England states’ policy goals and ISO-NE. Slocum said the way to align them is to have a board that is “directly accountable to either the states or to the communities within [the RTO’s] footprint.”
“This theoretical model that the ISOs came up with in the late ’90s to have a dispassionate board that is supposed to be directly responsive to the needs of folks within the ISO footprint has failed,” Slocum said. “We need to have a different governance structure that that has direct lines of accountability because that failure and lack of accountability is what’s driving most of the problems.”
The Western Energy Imbalance Market’s Governing Body approved the admission of “sub-entity” participants Wednesday, allowing utilities within the balancing authority area of a main WEIM participant to schedule and settle loads and resources independently.
The decision, which fell under the Governing Body’s primary approval authority in its shared authority with CAISO, was part of CAISO’s efforts to bring Xcel Energy’s Public Service Company of Colorado (PSCo) back to the WEIM.
In December 2019, PSCo said it would join the WEIM along with three utilities in its BAA — Black Hills Colorado Electric, Colorado Springs Utilities (CSU) and Platte River Power Authority — under a joint-dispatch agreement.
But in June, PSCo announced it was putting its WEIM plans on hold after CSU decided instead to join SPP’s Western Energy Imbalance Service (WEIS), with the intention of becoming a full RTO member. (See Xcel Delays Joining EIM to Examine Options.)
CAISO has been working with PSCo to convince it, along with Black Hills and Platte River, to join the WEIM.
Establishing sub-entity scheduling coordinators could bolster that effort, CAISO Vice President of Market Policy and Performance Anna McKenna wrote in her memo to the WEIM Governing Body.
“In addition to being applicable throughout the EIM, the EIM sub-entity category is an important provision for implementing the Public Service of Colorado balancing authority area into the EIM,” McKenna said. “The proposal allows PSCo to preserve the existing commercial arrangements that most of the various utilities in its balancing authority area operate under.”
CAISO’s plan to allow sub-entities “to settle load imbalances directly with the ISO” defines a load zone for each sub-entity. The EIM sub-entities would then submit base schedules for their load directly to the ISO, McKenna wrote.
“Base schedules are the load and supply schedules that reflect EIM participants’ planned operation and are used as the baseline against which imbalance energy is settled in the EIM,” she explained.
“The ISO will model each sub-entity’s load in the market as a customized distributed load aggregation point,” McKenna said. “This will enable the ISO to use existing practices to settle directly with the sub-entity.”
CAISO management proposed, and the Governing Body agreed, that the EIM sub-entities should be limited to those that are electric utilities embedded within an EIM entity balancing authority area that “do not receive long-term wholesale full requirements services from the EIM Entity.”
Eligible sub-entities must own distribution or transmission lines directly connected to the transmission system of the EIM entity “for the purpose of providing regulated electric service to eligible retail or wholesale customers.” They can also be a public utility that owns customer-serving resources, the CAISO plan said.
“Establishment as an EIM sub-entity is subject to the approval of the EIM entity that operates the balancing authority area in which the potential sub-entity is located,” McKenna wrote.
Stakeholders generally supported the plan, though some voiced concerns about introducing complications and confusion into the WEIM’s real-time interstate trading market.
The five members of the Governing Body unanimously endorsed the proposal.
The U.S. Department of Energy approved CAISO’s request last week for an emergency order allowing it to run natural gas plants that may exceed federal pollution limits as the ISO tries to maintain grid stability in the next two months.
“I hereby determine that an emergency exists in California due to a shortage of electric energy, a shortage of facilities for the generation of electric energy and other causes, and that issuance of this order will meet the emergency and serve the public interest,” Deputy Energy Secretary David Turk wrote in his order.
CAISO applied for the emergency order so that six generators, including aging power plants and new mobile units at existing facilities, can run free of emissions restrictions, starting this week, to provide up to 200 MW of additional supply.
“The CAISO respectfully requests that [Secretary of Energy Jennifer Granholm] issue the requested emergency order by Sept. 10, 2021, or a soon as possible thereafter, authorizing specific electric generating resources located within California to test and operate at their maximum generation output levels when directed to do so by the CAISO, notwithstanding air quality or other permit limitations,” CAISO COO Mark Rothleder wrote to Granholm.
CAISO’s cited reasons include high temperatures in the West, wildfires that threaten the bulk power system, and “drought conditions [that] are greatly affecting the availability of hydroelectric power.”
“Given these circumstances, state officials have identified a need to secure additional generating capacity to meet expected electricity demand and reserve requirements,” Rothleder wrote.
“Despite efforts undertaken by load serving entities and the CAISO to secure additional generating capacity, the CAISO continues to forecast potential supply deficiencies,” he said. “For September, the CAISO continues to forecast a significant supply deficiency to meet planning reserve requirements during evening hours.
“Granting this request for an emergency order and authorizing the operation of additional generating capacity identified in this request when conditions merit is critical to the CAISO maintaining reliability and meeting its load obligations,” he wrote.
Use Only in a Level 2 Emergency
Two of the covered resources — Greenleaf Unit 1 in Sutter County and Roseville Energy Park in Placer County — are working with the state to deploy new generating capacity by mid-September, a crucial time in California when temperatures can rise while hydroelectric generation dwindles. The 30-MW mobile units are part of the California Department of Water Resources’ efforts to add capacity.
“These covered resources will not have completed federal environmental permitting requirements by this date and will not operate unless they are subject to a DOE emergency order,” CAISO said.
The mobile units “are not equipped with best available control technology to control emissions and have not completed permitting processes to obtain their operating permit under Title V of the Clean Air Act,” the ISO said.
Four older units that could be covered by a DOE order are the Midway Sunset Cogeneration Facility Unit in Kern County, the Alamitos Energy Center in Long Beach, the Huntington Beach Energy Project in Orange County, and the Walnut Creek Energy Park in the city of Industry, near Los Angeles.
CAISO “understands that the electric generating units identified in this request have derated their facilities based on conditions set forth in their permits regarding nitrogen oxide emissions, heat output as well as fuel throughput,” the request said. “Accordingly, the CAISO anticipates that the emergency order it is requesting may result in exceedance of National Ambient Air Quality Standards under the Clean Air Act.”
The ISO said it intends to dispatch the units “at levels that exceed their permitted values” as on-call resources in its day-ahead timeframe if it issues a grid alert and will direct the units to operate only if it enters a Level 2 Energy Emergency Alert — “i.e. after the CAISO has initiated the dispatch of reliability demand response resources.”
“In this case, these resources would operate outside of permitted levels only as needed to help mitigate the risks of a system emergency and avoid the need for the CAISO to curtail native load,” Rothleder wrote. “In addition, the CAISO requests authority to dispatch the covered resources during transmission emergencies to reduce or eliminate the need to curtail native load to protect against the next contingency on the electric system.”
The Alamitos and Huntington Beach plants are two of the four once-through cooling plants that the state decided to keep open for reliability despite their harm to sea life. (See OTC Plants to Remain Open, Calif. Water Board Rules.)
Other Efforts
In April, FERC conditionally approved the Midway Sunset plant as the state’s first systemwide reliability-must-run resource. The 248-MW plant, built in an oil field in the 1980s, was scheduled to retire this year. (See CAISO’s 1st System RMR Agreement Set for Hearing.)
CAISO, the California Energy Commission and the California Public Utilities Commission have been working to obey Gov. Gavin Newsom’s July 30 emergency proclamation by connecting resources that can meet projected energy shortfalls this year and next. (Calif. Governor Proclaims Emergency as Blackouts Loom.)
In June, the CPUC ordered load-serving entities to deploy 11.5 GW of new resources to come online from 2023 to 2026, and, in July, CAISO took the rare step of using its capacity procurement mechanism to procure additional generating capacity. (CAISO Issues Urgent Call for More Summer Capacity.)
