ISO-NE has completed its work on the first two requirements to take effect under NERC’s revised geomagnetic disturbance (GMD) standard and will be fully compliant by the end of the year with requirements effective in July 2020, the RTO told the New England Power Pool’s Reliability Committee on Wednesday.
TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events) replaces TPL-007-1, effective July 1. TPL-007-3 added a regional variance for Canadian jurisdictions to TPL-007-2, which FERC approved in Order 851 in November (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)
NERC developed the new standard in response to FERC’s directives to improve how its initial GMD rules, approved in 2016, addressed the risks from “locally enhanced” events. It broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions.
TPL-007 compliance timeline | ISO-NE
The standard applies to planning coordinators (PCs), transmission planners (TPs) and transmission owners (TOs)/generator owners (GOs) with power transformer(s) with a high side, wye-grounded winding with terminal voltage greater than 200 kV.
NERC’s original standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event — defined as a one-in-100-year event. The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.
5 New Requirements
The standard adds five new requirements. R8, R9 and R10 require responsible entities to assess the potential implications of the supplemental GMD event on their equipment and systems. R8 requires the completion of a supplemental GMD vulnerability assessment at least once every five years. If the analysis finds the supplemental GMD event would cause cascading outages, the responsible entity must evaluate ways to reduce the likelihood or mitigate the impact of the event. NERC said its standard drafting team concluded that an evaluation was more appropriate than a formal corrective action plan “in light of the limitations of currently available tools for modeling localized GMD effects.”
R9 requires responsible entities to provide geomagnetically induced current (GIC) flow information based on the supplemental GMD event to owners of applicable bulk electric system power transformers in the planning area. R10 requires TOs and GOs to conduct a supplemental thermal impact assessment for BES power transformers where the maximum effective GIC value resulting from R9 is above a threshold (85 A per phase or greater).
Under R11 and R12, PCs and TPs must obtain GIC monitors and geomagnetic field data for their planning areas or system model areas. They must have at least one GIC monitor in their regions.
GMD storm in Fairbanks, Alaska, April 2011 | NASA
The new standard also made conforming changes to other requirements and revised the deadlines in R7 for corrective action plans required to address system performance issues identified in the benchmark vulnerability assessment.
ISO-NE’s Alex Rost said the RTO is already compliant with R1, which concerns the definition of PCs’ and TPs’ roles and responsibilities, and R2, maintaining system GIC models.
He said the RTO will be compliant by Dec. 1 with R5 (“Provide benchmark GIC flow information to applicable TOs and lead market participants [MPs] for applicable GOs”) and R9 (“Provide supplemental GIC flow information to applicable TOs and lead MPs for applicable GOs”), which take effect in January.
Rost said the analyses required by the standard can be “iterative” — results obtained in later stages of the study cycle may prompt the rerun of early-stage work.
He said most of the GIC modeling data required is already included in the New England system GIC model but that the RTO will notify applicable entities if modeling updates are needed.
Oklahoma Gas and Electric said Wednesday it has completed the acquisition of two Oklahoma generators from which it had previously bought power to meet its capacity needs.
OG&E said FERC’s approval of the transactions (EC19-49) was the final regulatory OK it needed to complete its purchases. Financial terms were not disclosed, but OG&E said last year it would spend $53 million to acquire the plants.
AES Shady Point is a 360-MW, coal-fired facility in Eastern Oklahoma; privately owned Oklahoma Cogeneration is a 146-MW combined cycle plant in Oklahoma City.
Shady Point facility | AES Shady Point
OG&E, a subsidiary of Oklahoma City-based OGE Energy, had contracts with both resources under the Public Utility Regulatory Policies Act of 1978. The legislation requires utilities to buy power from cogeneration plants built by non-utility power producers when the costs for that power are equal to or less than what the utility would spend to produce that power from a facility it would build and own.
Shady Point qualified for the cogeneration requirement by using some of its carbon dioxide emissions as a liquid and solid food-grade refrigerant for the poultry industry. However, OG&E said last year it was ending a five-year power purchase agreement with the plant, leading AES to announce it would close the facility.
OGE Energy CEO Sean Trauschke has said he expects “operational changes” to reduce Shady Point’s coal usage by more than 50%. The plant came online in 1991.
What to Do When ACE Conflicts with Interconnection Frequency?
By Rich Heidorn Jr.
The NERC Standards Committee on Wednesday postponed action on Arizona Public Service’s request to amend BAL-002-3 (Disturbance Control Standard — Contingency reserve for recovery from a balancing contingency event) after several members said they wanted to add the technical justification for its rejection to the record.
APS’ standards authorization request (SAR) proposed that compliance with BAL-002-2 requirement R1 would be reached once interconnection frequency has recovered, saying the change was needed to prevent the recovery of one event from contributing to the creation of another event.
Asked by the SC to provide a technical review, the Operating Committee in March recommended rejection of the SAR, citing advice from its the Resources Subcommittee (RS). “The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of [the] standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events (RBCEs),” the OC said, adding, “The concerns raised in this SAR can be addressed by other means.”
Arizona Public Service raised questions about how balancing authorities should react when their area control error (ACE) is at odds with an interconnection’s frequency. | Arizona Public Service
Sean Bodkin, NERC compliance policy manager for Dominion Resources Services, asked for the delay, saying the technical reasons for the rejection should be added to the record. Other committee members also sought additional information on the “other means” cited by the OC.
“I’m not a BAL expert, but it looked like [APS] had a legitimate concern,” said Steve Rueckert, director of standards for the Western Electricity Coordinating Council.
Duke Energy Carolinas’ Tom Pruitt, chair of the RS, said there are simpler and more effective solutions to the situation identified by APS.
“There is an option to go through compliance guidance and develop a compliance guidance document. … There is an option for a BA [balancing authority] with the existing standard to simply execute an emergency assistance agreement with one of its neighbors for this situation. No modification of the standard at all is needed…
“The bottom line is, [under the SAR,] the BA would be exempt from balancing his BA area and that goes right to the heart of the job of a balancing authority,” Pruitt continued. “If he’s not required to balance his BA, we’re missing the boat here.”
Gary Nolan, an APS regulatory compliance adviser who wrote the SAR, told the SC there were “some differences of opinion and some misunderstandings” of his company’s concerns.
APS was not seeking to have a BA shirk its responsibilities, he said, but attempting to draw attention to a situation in which a BA’s area control error (ACE) is low while the interconnection frequency is high.
“BAL-001 R2 has a balancing authority … responding to what the interconnection needs as opposed to what the balancing authority needs. … When [interconnection] frequency is high, a balancing authority is asked not to correct their ACE and make frequency worse but rather to — if their ACE is low, it’s okay for them to remain low if [interconnection] frequency is high,” he explained.
Nolan said BAL-002 could be read to direct a BA in that situation to “increase their generation — or possibly, if it gets to a point where they’re very near to the deadline, they may need to shed load in order to recover their ACE in time. … Shedding load should be something we would be abhorrent to and not want to do. … That’s not going to help the interconnection … when frequency is high.”
“I get it, and I can see where there’s an issue,” Rueckert responded. “But we need to remember that the Standards Committee is not a technical committee; we’re kind of a process committee, and I don’t know that we should be making a decision on this SAR on technical terms. I think that is the RS and the OC.”
Bodkin agreed. “I know I am completely unqualified to make any technical justification on the BAL standards and that’s the reason I actually wanted to see the technical information from the RS in the record.”
Revised Standards Grading Tool Approved
The SC also approved a revised Standards Grading Spreadsheet for the Periodic Review Standing Review Team to use in evaluating standards’ requirements.
A working group formed last September revised ambiguous questions; eliminated duplicate questions; converted multipart questions into single questions; and added a reference section linking to source documents. It is the first update of the tool since its development in 2016.
However, the tool won’t get used immediately because of the decision to suspend the review team’s work until next year to avoid conflicts with the Standards Efficiency Review. (See “Standards Grading Process on ‘Pause,’” NERC Standards Committee Briefs: March 20, 2019.)
After five years of discussion, MISO and PJM are still slogging through development of an alternative to their “freeze date” used to grandfather permissible unscheduled transmission flows that predated their seam.
And while the RTOs promise progress on the issue, they acknowledge that outside entities with a stake in any changes are still resistant to a proposed solution, stakeholders learned Tuesday.
The RTOs rely on the April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before creation of the seam between their markets. That date is used to establish acceptable flows in both the market-to-market (M2M) process and transmission loading relief.
Andy Witmeier, of MISO’s seams administration team, said the RTOs still agree that the freeze date needs updating.
“We’re more than 15 years away from it now, and issues with the date have become prominent,” Witmeier told stakeholders during a MISO-PJM Joint and Common Market conference call. Those issues primarily have to do with how designated network resources are dispatched and determining eligibility for transmission service requests.
But five years on, the RTOs are still facing opposition from parties to their congestion management process (CMP), which includes MISO, PJM, SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. The CMP was established to minimize unscheduled market — or loop — flows among neighboring balancing areas.
All CMP parties stand to be affected by a change in the freeze date, MISO staff have said.
In November, MISO and PJM announced that their original goal of a full freeze date replacement by June 2019 was too optimistic. Now, the RTOs say they will continue talks on a possible replacement throughout the year and hope to implement a solution in 2020.
FFE vs. FFL
In M2M procedures between RTOs, an RTO’s entitled firm usage is classified as a firm flow entitlement (FFE). In the transmission loading relief process utilized for nonmarket entities in the CMP, an RTO’s entitled firm usage is classified as a firm flow limit (FFL).
Witmeier said MISO and PJM were close to a solution last year, but that nonmarket entities party to the CMP had issues with how the proposal might impact FFLs.
The RTOs’ proposal would divide flowgate allocation — or FFEs — among four separate “buckets” to prioritize access to the flowgates. (See “Freeze Date Update,” MISO-PJM Markets Meeting Addresses Seams Issues.)
The first bucket — which would get primary consideration for flowgate needs — would consist of active designated network resources predating the freeze date and historic transmission service requests.
A second bucket would consist of active designated network resources dating after the freeze date, while a third would be used for transfers from local balancing authorities with excess generation to LBAs short on generation.
The fourth, lowest-priority bucket would be for market-wide transfers based on RTO transmission planning.
MISO and PJM last summer changed their policies to make post-freeze date designated network resources with a defined dispatch order eligible to receive FFE allocations — a small piece of the RTOs’ broader proposed solution.
Witmeier said most CMP entities favor completing an FFE solution by mid-2020 while continuing to work on how FFLs would be handled. However, some want any solution delayed until both FFEs and FFLs can be addressed.
“Obviously, we have to have a unanimous agreement from all parties. … We’re not there yet,” Witmeier said.
‘A Long Time’
MISO, PJM and CMP entities have been working for about five years on a freeze date alternative through their Congestion Management Process Working Group.
Witmeier also said the two RTOs are specifically working on how to account for FFE allocation priorities and in what order they would curtail the overallocation of rights on a particular flowgate.
A joint white paper on the matter that would detail an alternative way to calculate the freeze date is still in the works, Witmeier added.
Customized Energy Solutions’ David Sapper asked if MISO and PJM could move to a FERC filing on a freeze date alternative without all nonmarket entities signing on.
“Five years is a long time,” Sapper observed.
PJM Director of Energy Market Operations Tim Horger said the two RTOs are considering substitutes to unanimous accord and may consider a filing that not all parties have signed on to. He also said parties to the CMP are “frustrated” that talks on a potential solution have taken this long.
“There is going to be a path forward shortly,” Horger promised stakeholders.
MISO and PJM staff promised to return to the Aug. 27 JCM meeting with an update.
WESTBOROUGH, Mass. — ISO-NE told the Planning Advisory Committee on Tuesday that it plans to conduct all three economic studies requested by stakeholders last month.
Marianne Perben, ISO-NE manager of technical studies and resource adequacy, presented the 2019 Economic Study Draft Scope of Work and High Level Assumptions to the PAC. (See “Economic Study Requests Focus on Wind,” ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)
The studies will cover:
A New England States Committee on Electricity (NESCOE) request to analyze various scenarios for integrating offshore wind by 2030, focusing on the impact on the transmission system and wholesale market. The study will examine a range of 2,000 to 8,000 MW of OSW resources, Perben said.
A request by transmission developer Anbaric Development Partners to review the impacts of OSW on energy market prices, emissions and regional fuel security in 2030. The study will look at an 8,000- to 12,000-MW range of OSW.
A RENEW Northeast request to evaluate transmission upgrades that would increase the hourly operating limits of the Orrington South interface in Maine.
The three studies will rely on a number of common assumptions, including: modeling Forward Capacity Market and energy-only generators at their seasonal claimed capability; using the most recent U.S. Energy Information Administration forecasts for New England coal, oil and natural gas prices; and reflecting CO2, SO2 and NOx prices in fossil fuel generation. Michael Henderson, the RTO’s director of regional planning and coordination, cautioned participants that “these are economic studies, not detailed transmission studies.”
The RTO uses these threshold prices to facilitate analysis of load levels where the amount of $0/MWh resources exceeds the system load. | ISO-NE
In response to a question about why the RENEW study would exclude the western Maine cluster of resources in the interconnection queue, Perben said the cluster was not part of the request.
Asked about varying threshold prices in the analysis, Perben said ISO-NE uses them to facilitate analysis of load levels where the amount of $0/MWh resources exceeds the system load. They “are really just a way to know when to curtail those resources,” she said.
New Hampshire 2029 Needs Assessment Outlined
Jinlin Zhang, the RTO’s lead engineer for transmission planning, gave the committee a briefing on the New Hampshire 2029 Needs Assessment.
In February, ISO-NE suspended its New Hampshire 2027 Solutions Study process in order to incorporate changes in the draft 2019 Capacity, Energy, Loads and Transmission (CELT) forecast data, which showed the regional net load figure the RTO was using was too high.
The RTO used the draft 2019 forecasts to update the models to reflect the change in load, energy efficiency and solar PV volumes from the 2018 CELT, Zhang said.
She highlighted the “very important date” of June 10 as the deadline to notify the RTO of any resources it should consider including in the Needs Assessments.
2019 CELT winter forecasts | ISO-NE
Resources to be included are those that have cleared a Forward Capacity Auction, have signed contracts from state-sponsored requests for proposals, or are otherwise obligated by contract.
Two projects that received capacity supply obligations (CSOs) in FCA 13 have been added to the 2029 cases, she said. A 632-MW combined cycle plant in Connecticut is far from the study area and therefore modeled offline, while a 123-MW solar farm connecting into the Albion Road 115-kV substation in Maine is modeled at about 32 MW, or 26% of nameplate.
In addition, four generators have been set as out-of-service in the 2029 cases, with one generator in New Hampshire (Schiller 4 at about 48 MW) fully delisted for the second consecutive FCA, which is the cutoff for considering the resource unavailable for dispatch when performing a Needs Assessment. If a resource does not operate for three calendar years in a row, it is deemed to be retired.
The New Hampshire 2029 Needs Assessment will consider sensitivity study scenarios of the unavailability of all major generators in Central New Hampshire, as well as the addition of the 1,090-MW New England Clean Energy Connect (NECEC) project that would deliver Canadian hydropower and wind energy to the Larrabee Road 115-kV substation in Maine. NECEC was proposed in response to a solicitation by Massachusetts utilities.
Although NECEC does not yet have an approved contract from Massachusetts regulators, ISO-NE recognizes the project may be approved prior to or soon after the completion of the Needs Assessment, Zhang said.
In addition, the RTO will examine the unavailability of one Comerford and one Moore hydro generator.
The study models photovoltaic generation based on the draft 2019 CELT forecast.
“And when we studied generation unavailable, we studied generation unavailable in the neighboring area,” Zhang said. “All interface transfers are within their limits, demonstrating that the established reserves are acceptable.”
The RTO plans to post the updated 2029 Needs Assessment intermediate study files in Q3 2019. The assessment is expected to be completed by Q3 or Q4 2019, she said.
New Hampshire Needs Assessment changes | ISO-NE
Emergency Actions Eyed to Address Potential Shortfall in Operable Capacity
ISO-NE projects the region’s net installed capacity requirements (ICRs) will increase by 480 MW by 2028 and that operating procedures could be needed to overcome a shortage of “operable” capacity.
Those were some of the highlights of a presentation the RTO gave the PAC on resource adequacy studies to be included in the 2019 Regional System Plan.
Peter Wong, the RTO’s manager of studies and assessment, said net ICR — 33,390 MW this year — is projected to increase to 33,870 MW by 2028.
Wong said the 34,839 MW of “known resources,” based on CSOs from FCA 13, are sufficient to meet the net ICR values through the 2028/29 capacity commitment period.
A comparison of the representative net ICRs with the FCA 13 resources plus the energy efficiency forecast shows a surplus of 2,291 MW in 2029, assuming no resource retirements, he said.
However, the RTO’s analysis of “operable” capacity — which deducts unplanned generator outages and gas-fired generation that may not be able to obtain fuel during peak winter periods — indicates the region may have to rely on load or capacity relief measures under Operating Procedure 4 (OP-4) to avoid shortfalls.
The analysis deducted 2,100 MW from the summer capacity based on historical unplanned outages, and 8,600 MW in winter based on the highest planned and unplanned generator outages during 2014-2018 and the highest amount of gas-fired generation at risk during the three-week winter peak.
Under 90/10 peak load conditions, the region could have operable capacity shortfalls of -1,150 to -2,500 MW during the summer and -1,370 to -2,500 MW during the winter.
Assuming 50/50 peak load conditions, New England could fall short of operable capacity during the winter peak for the entire study period and during the summer starting with delivery year 2024/25. Operable capacity shortfalls range from -310 to -470 MW during the summer and -160 to -1,200 MW during the winter.
The RTO said OP-4 actions of up to Action 6 (a 5% voltage reduction) could be needed to meet 50/50 loads and up to Action 9 (requests of all generation not contractually available to market participants and voluntary load curtailments by large industrial and commercial customers) to serve 90/10 loads.
Other operating procedures anticipated include depleting 10- and 30-minute operating reserves and importing power from other regions.
Wong said the RTO is anticipating a possible change in what has historically been a summer-peaking region.
“We are reviewing the growth in demand-side resources and the penetration of PV both behind the meter and in front of the meter, and the penetration of heat pumps,” Wong said. “Penetration of PV is not only shifting the time of the daily peak; it is possible that the system will shift to dual-peaking and then to a winter-peaking system.”
The Power Supply Planning Committee will conduct a final review of all assumptions on June 20 and July 25 and will review ISO-NE recommendation of ICR values Aug. 9 and Aug. 29 ahead of a Reliability Committee review and vote on ICR values on Aug. 20 and Sept. 25.
The Participants Committee will review and vote on the recommended ICR values Oct. 4, which will be filed with FERC by Nov. 5.
The federal judge overseeing PG&E Corp.’s bankruptcy case gave the company four more months to come up with a Chapter 11 reorganization plan at a hearing Wednesday.
Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, extended the 120-day period under which PG&E and its utility subsidiary Pacific Gas and Electric have exclusive rights to file a reorganization plan with the court.
Montali gave the companies through September to come up with a proposal, though he said he could shorten that time if he chose.
The companies filed for bankruptcy Jan. 29, citing at least $30 billion in liabilities for wildfires sparked by transmission and distribution lines. (See PG&E Files for Bankruptcy.) The 120-day exclusivity period was set to run out next week.
Montali’s extension was a compromise. PG&E had asked for six more months in the hopes that California Gov. Gavin Newsom and the State Legislature might offer the state’s investor-owned utilities wildfire liability relief later this year.
Lawyers representing wildfire victims had urged Montali to deny the extension, while creditors had recommended a four-month reprieve. The judge said he was inclined to grant PG&E’s motion, but after hearing from the parties, he decided to accept the recommendation of the creditors’ committee.
“This judge has never been a fan of exclusivity but is a fan of practical consequences,” Montali said. He explained he did not want to deal with competing reorganization plans that might be unworkable.
Montali also approved PG&E’s creation of a $100 million fund to aid wildfire victims who lack housing or have other urgent needs. Many of those displaced by the November 2018 Camp Fire, the deadliest and most destructive in state history, are still living in tents and recreational vehicles in the destroyed town of Paradise.
One victims’ lawyer said the fund was a ploy by PG&E to generate good will with the governor and lawmakers. PG&E and the state’s other two large IOUs — Southern California Edison and San Diego Gas & Electric — want policymakers to lessen their wildfire liability under the state’s strict liability standard, known as inverse condemnation.
PG&E is a “pariah in Sacramento” and needs help winning reforms, the plaintiffs’ lawyer Robert Julian told the judge.
Julian said that in the same courthouse, Judge William Alsup is overseeing PG&E’s criminal probation related to the 2010 San Bruno gas pipeline explosion and has ordered the company’s new leaders to tour the devastation in Paradise. (See PG&E Probed by Plaintiffs’ Lawyers, SEC.)
The California Department of Forestry and Fire Protection recently concluded PG&E’s equipment had started the Camp Fire, which killed at least 85 people and destroyed nearly 19,000 structures. PG&E admitted weeks ago that a tower on its 100-year-old Caribou-Palermo line near Paradise had likely sparked the massive blaze. (See Cal Fire Pins Deadly Camp Fire on PG&E.)
“The only question is whether it’s homicide or manslaughter in the Camp Fire because they knew that tower was going to fail,” Julian said.
Montali said that as a bankruptcy judge, he could only approve or deny PG&E’s request to establish the aid fund, and that he had no cause to deny it.
“You’re saying, ‘You get brownie points with the governor and Judge Alsup,’” Montali told Julian. “I don’t care about that.”
ISO-NE has completed its work on the first two requirements to take effect under NERC’s revised geomagnetic disturbance (GMD) standard and will be fully compliant by the end of the year with requirements effective in July 2020, the RTO told the New England Power Pool’s Reliability Committee on Wednesday.
TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events) replaces TPL-007-1, effective July 1. TPL-007-3 added a regional variance for Canadian jurisdictions to TPL-007-2, which FERC approved in Order 851 in November (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)
NERC developed the new standard in response to FERC’s directives to improve how its initial GMD rules, approved in 2016, addressed the risks from “locally enhanced” events. It broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions.
The standard applies to planning coordinators (PCs), transmission planners (TPs) and transmission owners (TOs)/generator owners (GOs) with power transformer(s) with a high side, wye-grounded winding with terminal voltage greater than 200 kV.
NERC’s original standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event — defined as a one-in-100-year event. The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.
5 New Requirements
The standard adds five new requirements. R8, R9 and R10 require responsible entities to assess the potential implications of the supplemental GMD event on their equipment and systems. R8 requires the completion of a supplemental GMD vulnerability assessment at least once every five years. If the analysis finds the supplemental GMD event would cause cascading outages, the responsible entity must evaluate ways to reduce the likelihood or mitigate the impact of the event. NERC said its standard drafting team concluded that an evaluation was more appropriate than a formal corrective action plan “in light of the limitations of currently available tools for modeling localized GMD effects.”
R9 requires responsible entities to provide geomagnetically induced current (GIC) flow information based on the supplemental GMD event to owners of applicable bulk electric system power transformers in the planning area. R10 requires TOs and GOs to conduct a supplemental thermal impact assessment for BES power transformers where the maximum effective GIC value resulting from R9 is above a threshold (85 A per phase or greater).
Under R11 and R12, PCs and TPs must obtain GIC monitors and geomagnetic field data for their planning areas or system model areas. They must have at least one GIC monitor in their regions.
The new standard also made conforming changes to other requirements and revised the deadlines in R7 for corrective action plans required to address system performance issues identified in the benchmark vulnerability assessment.
ISO-NE’s Alex Rost said the RTO is already compliant with R1, which concerns the definition of PCs’ and TPs’ roles and responsibilities, and R2, maintaining system GIC models.
He said the RTO will be compliant by Dec. 1 with R5 (“Provide benchmark GIC flow information to applicable TOs and lead market participants [MPs] for applicable GOs”) and R9 (“Provide supplemental GIC flow information to applicable TOs and lead MPs for applicable GOs”), which take effect in January.
Rost said the analyses required by the standard can be “iterative” — results obtained in later stages of the study cycle may prompt the rerun of early-stage work.
He said most of the GIC modeling data required is already included in the New England system GIC model but that the RTO will notify applicable entities if modeling updates are needed.
What to Do When ACE Conflicts with Interconnection Frequency?
By Rich Heidorn Jr.
The NERC Standards Committee on Wednesday postponed action on Arizona Public Service’s request to amend BAL-002-3 (Disturbance Control Standard — Contingency reserve for recovery from a balancing contingency event) after several members said they wanted to add the technical justification for its rejection to the record.
APS’ standards authorization request (SAR) proposed that compliance with BAL-002-2 requirement R1 would be reached once interconnection frequency has recovered, saying the change was needed to prevent the recovery of one event from contributing to the creation of another event.
Asked by the SC to provide a technical review, the Operating Committee in March recommended rejection of the SAR, citing advice from its the Resources Subcommittee (RS). “The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of [the] standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events (RBCEs),” the OC said, adding, “The concerns raised in this SAR can be addressed by other means.”
Arizona Public Service raised questions about how balancing authorities should react when their area control error (ACE) is at odds with an interconnection’s frequency. | Arizona Public Service
Sean Bodkin, NERC compliance policy manager for Dominion Resources Services, asked for the delay, saying the technical reasons for the rejection should be added to the record. Other committee members also sought additional information on the “other means” cited by the OC.
“I’m not a BAL expert, but it looked like [APS] had a legitimate concern,” said Steve Rueckert, director of standards for the Western Electricity Coordinating Council.
Duke Energy Carolinas’ Tom Pruitt, chair of the RS, said there are simpler and more effective solutions to the situation identified by APS.
“There is an option to go through compliance guidance and develop a compliance guidance document. … There is an option for a BA [balancing authority] with the existing standard to simply execute an emergency assistance agreement with one of its neighbors for this situation. No modification of the standard at all is needed…
“The bottom line is, [under the SAR,] the BA would be exempt from balancing his BA area and that goes right to the heart of the job of a balancing authority,” Pruitt continued. “If he’s not required to balance his BA, we’re missing the boat here.”
Gary Nolan, an APS regulatory compliance adviser who wrote the SAR, told the SC there were “some differences of opinion and some misunderstandings” of his company’s concerns.
APS was not seeking to have a BA shirk its responsibilities, he said, but attempting to draw attention to a situation in which a BA’s area control error (ACE) is low while the interconnection frequency is high.
“BAL-001 R2 has a balancing authority … responding to what the interconnection needs as opposed to what the balancing authority needs. … When [interconnection] frequency is high, a balancing authority is asked not to correct their ACE and make frequency worse but rather to — if their ACE is low, it’s okay for them to remain low if [interconnection] frequency is high,” he explained.
Nolan said BAL-002 could be read to direct a BA in that situation to “increase their generation — or possibly, if it gets to a point where they’re very near to the deadline, they may need to shed load in order to recover their ACE in time. … Shedding load should be something we would be abhorrent to and not want to do. … That’s not going to help the interconnection … when frequency is high.”
“I get it, and I can see where there’s an issue,” Rueckert responded. “But we need to remember that the Standards Committee is not a technical committee; we’re kind of a process committee, and I don’t know that we should be making a decision on this SAR on technical terms. I think that is the RS and the OC.”
Bodkin agreed. “I know I am completely unqualified to make any technical justification on the BAL standards and that’s the reason I actually wanted to see the technical information from the RS in the record.”
Revised Standards Grading Tool Approved
The SC also approved a revised Standards Grading Spreadsheet for the Periodic Review Standing Review Team to use in evaluating standards’ requirements.
A working group formed last September revised ambiguous questions; eliminated duplicate questions; converted multipart questions into single questions; and added a reference section linking to source documents. It is the first update of the tool since its development in 2016.
However, the tool won’t get used immediately because of the decision to suspend the review team’s work until next year to avoid conflicts with the Standards Efficiency Review. (See “Standards Grading Process on ‘Pause,’” NERC Standards Committee Briefs: March 20, 2019.)
Minnesota’s Xcel Energy is aiming to be coal-free by 2030, supported by extending service of its nuclear plant and using more natural gas-fired generation, the utility announced Monday.
The company announced that it will close its two remaining coal plants a decade earlier than originally scheduled but extend operation of the Monticello Nuclear Generating Plant on the Mississippi River into 2040, 10 years after the plant’s current license expires. The nuclear extension will require both state and federal approvals.
The 511-MW Allen S. King Generating Station near the Twin Cities will close in 2028, while the 876-MW Sherco III unit of the Sherburne County (Sherco) Generating Station will close in 2030, Xcel said in a press release. The company has already said it will shutter the 680-MW Sherco I and 682-MW Sherco II in 2023 and 2026, respectively. It plans to build a new natural gas plant on the Sherco site.
Sherco Generating Station | Xcel Energy
The announcement comes as Xcel comes closer to securing the purchase of the gas-fired Mankato Energy Center from Southern Co. for about $650 million — a move originally opposed by the Sierra Club, which removed its comments in opposition after Xcel’s Monday announcement (18-702).
The company said the changes will take place while it triples its renewable portfolio, with plans to add 1,850 MW of wind by 2022 and about 3,000 MW of new solar by 2030.
Xcel said the acceleration of eliminating coal dependence “is another milestone in the company’s clean energy transition.”
The company will submit the retirement proposals, included in its 15-year resource plan, to the Minnesota Public Utilities Commission on July 1. The company has said it plans to reduce carbon emissions to 80% below 2005 levels by 2030 and go completely carbon-free in 2050.
“This is a significant step forward as we are on track to reduce carbon emissions by more than 80% by 2030 and transform the way we deliver energy to our customers,” said Chris Clark, president of Xcel Energy in Minnesota, North Dakota and South Dakota.
After the Xcel retirements, Minnesota will be left with just one coal plant, Minnesota Power’s 1,000-MW Boswell power plant in Cohasset.
Xcel’s move also comes after Minnesota Gov. Tim Walz announced in March that the state would strive to use 100% clean energy by 2050, joining Wisconsin, which has a similar goal. The company joins a spate of MISO member companies that have pledged to go coal-free or carbon-free, including MidAmerican Energy, DTE Energy, Consumers Energy and Southern Co. Other MISO companies have deep carbon-reduction goals, including American Electric Power, Alliant Energy, Ameren, NextEra Energy and WEC Energy Group.
As a result, some MISO organizations and companies have asked the RTO to better account for significant renewable goals or decarbonization commitments in its transmission planning. (See MISO Going Back to the Futures for MTEP 20.)
FOLSOM, Calif. — CAISO’s RC West has been shadowing Peak Reliability as the ISO prepares to take over reliability coordinator functions throughout most of the West by the end of this year.
The first phase of the two-month shadow operations — in which RC West employees have been mirroring Peak workers around the clock “in listening mode mainly” — will conclude soon, Tim Beach, RC West’s director of operations, told the organization’s Oversight Committee on Tuesday.
So far, RC West has been included on nearly every call, including an energy emergency alert (EEA) event just a few hours into the process, Beach said. “We’re very happy about that,” he said.
The next phase starts June 1, when RC West and Peak reverse roles. RC West employees will talk to balancing authorities, and Peak will step in “if they don’t like how things are going,” Beach said.
Nancy Traweek, executive director of system operations at CAISO, told the committee that the Western Electricity Coordinating Council had provisionally approved the ISO’s bid to serve as an RC and that the matter is now in NERC’s hands. NERC and WECC plan to observe RC West’s shadow operations in the coming weeks, Traweek said.
Everything is going as planned, she told the committee.
RC West has secured agreements from 39 entities in the Western Interconnection, including Arizona Public Service, PacifiCorp and Seattle City Light. Its footprint stretches from the Canadian border into northern Baja California, and from the Pacific Ocean to the Rocky Mountains.
CAISO plans to become the RC for California and Baja California on July 1. BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside California on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.
The Oversight Committee had its first in-person meeting in March, when it elected its chair, Michelle Cathcart, vice president of transmission system operations with the Bonneville Power Administration, and vice chair, Steve Cobb, director of transmission and generation operations at Arizona’s Salt River Project. (See CAISO RC Oversight Committee Elects Leaders.)
The committee plans to meet monthly throughout 2019. Its members represent the transmission owners and balancing authorities in RC West.
At Tuesday’s meeting, Cathcart led a discussion about the possibility that WECC might revive its former RC operating committee and play a role in coordinating functions between the West’s three new RCs. The proposal is in an early stage, she said.
The plan didn’t appear to generate much enthusiasm among committee members, Cathcart noted. “I’m not hearing a lot of excitement in this room,” she said.
