MISO and PJM said Tuesday they will propose changes to how they determine flowgate rights in a white paper in November.
The RTOs use an April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before the creation of their seam. That date is used to determine both firm flow entitlements (FFEs) used in market-to-market settlements and firm flow limits (FFLs) used in transmission loading relief (TLR).
Earlier in August, MISO staff said the RTOs were considering filing a freeze date solution that would almost certainly be opposed by nonmarket parties to the congestion management process, leaving a decision up to FERC.
During a Joint and Common Market conference call, however, the RTOs said they hope they will be able to find an agreement with the nonmarket parties — including SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. — by November. (See Outside Parties Slow MISO-PJM Freeze Date Thaw.)
PJM and MISO footprints | MISO, PJM
MISO and PJM’s proposed solution would divide flowgate rights by age, with priority to network resources from 2004 and earlier, followed by: network resources from 2004 or later; transfers between local balancing authorities to make up shortages on a pro rata basis; and RTO load served by RTO dispatch — in that order.
“Of course, the current freeze date process is not suitable for markets right now. … Of course, the solution will increase transfer rights for markets over nonmarket entities. That’s been a big concern for the nonmarket,” Andy Witmeier, of MISO’s seams administration team, said earlier in August. Witmeier said nonmarket neighbors of the RTOs are concerned that their reliability may be impacted by a decrease in non-firm transfer availability. They also fear that an increase in firm limits for post-2004 network resources could lead to more curtailments of non-firm transfers for those outside the two markets.
Witmeier had said MISO and PJM could either file the freeze date changes with changes only to the RTOs’ FFEs, leaving FFLs alone. But MISO staff said they would prefer a full solution that includes FFLs or to file a contested solution and let FERC decide.
The white paper will discuss the solution only as it applies to FFEs. Joe Rushing, of PJM’s interregional market relations team, said Tuesday that the RTOs will continue to discuss with neighboring balancing authorities how FFLs can be updated from the freeze date.
Rushing said the RTOs may consider creating a market mechanism to cut a portion of firm market flows when curtailment of nonmarket flows doesn’t provide enough relief to avoid TLRs. He also said they plan to study individual flowgates to figure out if some might be overtaxed.
He promised more discussion on the issue at the JCM meeting Nov. 19, when the RTOs expect to unveil the white paper.
No MISO Guarantee on PJM Customers’ Revenue Rights
Meanwhile, the RTOs have conceded there is no way for MISO to guarantee PJM’s customer-funded incremental auction revenue rights (IARRs) will result in a corresponding increase in FFEs.
However, the RTOs are promising more accurate estimates of increased flowgate entitlements when an IARR requires a joint coordinated study on the transmission upgrade.
Rushing said the grid operators have received little stakeholder comment on the small potential for financial risks to PJM members.
Both RTOs offer IARRs, which reflect upgrades that increase capability on their transmission facilities. IARR megawatts are awarded for the additional capability created for the life of the upgrade or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices. However, PJM’s process provides an additional option that allows a specified IARR to be awarded when a customer agrees to fund transmission upgrades necessary to support the new auction revenue rights request. PJM is also obligated to guarantee at least 80% of IARR megawatts. (See PJM, MISO Plan Study to Coordinate Incremental ARRs.)
MISO has repeatedly said it cannot make guarantees on future FFE allocations to PJM members. PJM staff have said it’s possible they won’t be able to guarantee the 80% share if transmission upgrades affect the MISO system.
The federal judge overseeing PG&E’s bankruptcy relinquished a major part of the case dealing with wildfire damages to another federal judge while a third part of the case is heading to state court for resolution.
U.S. Bankruptcy Judge Dennis Montali said he understood the divided process is awkward, but he wanted to speed up the case and protect the rights of fire victims.
He decided a federal district court judge, not a bankruptcy judge, should estimate the wildfire damages, which are a key component of the utility’s bankruptcy.
Some parties have suggested PG&E might be required to pay $10 billion to $40 billion to victims of the wildfires that scorched Northern California in the past two years.
“I felt compelled to toss the ball to the district court,” Montali told lawyers during a bankruptcy hearing Tuesday. The judge said he would be doing a disservice to victims to try to rush through the complex and unusual proceeding while attending to the rest of the massive bankruptcy case.
Phyllis J. Hamilton, chief judge for the Northern District of California, approved Montali’s request to assign the estimation proceeding to a trial judge. District Court Judge James Donato, whose courtroom is in the same building as Montali’s, will now hear the matter.
Montali said the state Legislature’s July passage of AB 1054 had increased the pressure to resolve PG&E’s bankruptcy more quickly. The law allows PG&E to share in a $21 billion wildfire damages fund administered by the state but only if it exits bankruptcy by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
“While that may seem a long way in the future, and no doubt is far too long for thousands of victims, the complexity of these Chapter 11 cases, the requirements of Chapter 11 and the need for parallel hearings and rulings by the California Public Utilities Commission — most of which pertain to regulatory matters and contractual obligations that exist apart from the wildfire claims — impose very difficult time limits on all parties, including the court,” the judge wrote.
A CPUC attorney told the judge Tuesday the commission would need time to weigh the effects of a reorganization plan on ratepayers and PG&E’s financial stability.
Earlier this month, Montali agreed to allow claims against PG&E over the October 2017 Tubbs Fire to be decided in state court.
The Tubbs Fire, which killed 22 people, destroyed more than 5,600 structures and leveled a section of Santa Rosa, Calif., was the most destructive in state history until the Camp Fire in November 2018 killed 86 people and burned 18,804 structures, destroying most of the town of Paradise.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) blamed the Camp Fire on a faulty PG&E transmission line but said the Tubbs Fire was caused by shoddy wiring on private property.
Plaintiffs’ lawyers still want a judge or jury to decide PG&E’s liability for the Tubbs Fire, however, and Montali agreed on Aug. 16 to lift a stay on legal actions against the company and allow the matter to go to state court on an expedited basis. (See Only PG&E Can File Bankruptcy Plan, Judge Says.)
PG&E has said it plans to file a reorganization plan by Sept. 9, but that plan can’t be finalized without a better idea of the damages from the Camp Fire, the Tubbs Fire and a rash of other fires in October 2017, most of which have been blamed on PG&E equipment.
The utility has indicated it wants to establish a “capped fund” to pay wildfire victims, but Montali said he needs to know where to set the cap before approving a compensation fund.
FERC ordered paper hearings Monday in disputes over the criteria PJM used to reject several hydroelectric resources from pseudo-tying into the RTO’s grid.
Both Brookfield Energy Marketing and Cube Yadkin Generation said PJM erred when it determined some of their generating resources didn’t meet the RTO’s pseudo-tie requirements, preventing the companies from offering capacity.
Brookfield Complaint
In January, Brookfield challenged PJM’s assertion its Calderwood and Cheoah generating facilities did not pass the market-to-market flowgate test or meet its extraterritorial deliverability requirements, despite maintaining a firm point-to-point service from the Tennessee Valley Authority into Duke Energy’s balancing authority area at an annual cost of $5 million. The company says it has held capacity obligations in PJM since 2014.
PJM told Brookfield in March 2018 its tests determined the facilities failed for 38 flowgates. A follow-up test three months later found the facilities failed “19 transmission elements.” PJM rejected as insufficient a report prepared by Quanta Technology that affirmed Brookfield’s point-to-point service complies with the RTO’s requirements.
Brookfield Energy Marketing’s Calderwood Dam is on the Little Tennessee River in Blount County, Tenn.
PJM’s current pseudo-tie rules were approved by the commission in November 2017. The order included a five-year transition period for resources that had an existing pseudo-tie and had cleared in a capacity auction before May 2017 (ER17-1138). As a result of the failed tests, PJM said the Brookfield generators would be ineligible to participate in its capacity auction for the 2022/23 delivery year, after the transition period expired.
FERC ruled Aug. 26 that Brookfield’s complaint raised legitimate concerns about how PJM applied its requirements (EL19–34). The commission noted PJM’s Tariff and Manuals do not specify the “deliverability criteria” the RTO uses for its evaluations.
“The record is not clear as to what deliverability criteria PJM uses to determine whether pseudo-tied resources can participate in the auctions, whether it uses those deliverability criteria consistently for all projects or how PJM evaluated the Brookfield facilities,” the commission said. ” … PJM has not sufficiently explained why the Brookfield facilities failed the M2M flowgate test while other external generators affecting the same flowgate (Flowgate No. 93209) did not.”
However, the commission denied Brookfield’s request to extend the five-year transition period. PJM said doing so would be inappropriate because the transition period is memorialized in the Tariff and would require a showing that the original transition was unjust and unreasonable. “Brookfield has presented neither a basis on which the commission could grant its requested interim relief nor a demonstration such relief would be appropriate in these circumstances,” FERC said.
Cube Yadkin Complaint
Cube Yadkin Generation filed its complaint after PJM informed it in June 2018 that its 220-MW Yadkin Project — the Tuckertown, High Rock, Falls and Narrows hydroelectric sites on the Yadkin River about 75 miles from Charlotte, N.C. — did not meet the “electrical distance” requirement under its pseudo-tie rules.
FERC approved the electrical distance test in its 2017 order, saying it struck an appropriate balance between allowing external resources to participate in PJM’s capacity market while providing the RTO with reliability assurance. The commission said it accepted PJM’s representation that the further its state estimator model extends beyond its own borders, the less resilient the PJM system becomes to data losses and inaccuracies.
Yadkin River hydro project | Cube Yadkin Generation
In its Aug. 26, order, the commission said Yadkin had raised factual questions about how PJM conducted the electrical distance test (EL19-51). Cube Yadkin said PJM’s identification of three electrically closest buses for the project is electrically impossible because the series arrangement of the resources — with grid connections to only High Rock and Badin — means there can only be two closest buses.
FERC said PJM did not directly dispute Cube Yadkin’s arguments but responded each site’s location has a “unique set of paths through and out of the Yadkin area to the PJM border and, given these unique paths, finding differences between each location is not unexpected.”
The commission said that raised questions as to how PJM’s algorithm selects the buses and paths used in the electrical distance test and whether the selection of the wrong bus could cause a generator to fail when it would have otherwise passed.
FERC gave PJM 30 days to respond to its questions about its methodology, with responses by Brookfield and Yadkin due within 15 days of the RTO’s filings. “After receipt of these filings, commission staff is authorized to establish additional procedures, including a staff technical conference,” FERC said.
FERC and NERC on Tuesday asked for comment on a proposal to change how they disclose information on violations of critical infrastructure protection (CIP) rules.
FERC and NERC staffs published a white paper outlining proposed changes to their current procedures, which they said “may not be achieving an appropriate balance of security and transparency.”
From 2010 until December 2018, the public version of NERC’s CIP Notices of Penalty contained similar information as the confidential submission to FERC but excluded material NERC considered Critical Energy/Electric Infrastructure Information (CEII), such as the name of the registered entity. In 2019, NERC began submitting public line-by-line redactions of information claimed as CEII.
The commission initially treats information claimed by NERC as CEII as non-public but has reviewed those determinations — and sometimes released additional information — in response to Freedom of Information Act (FOIA) requests. The staffs said they reconsidered their approach in response to an increase in FOIA requests.
Duke Energy, which is headquartered in Charlotte, N.C., was fined $10 million for CIP violations earlier this year. | Duke Energy
The white paper proposes that NERC CIP NOPs include a public cover letter disclosing the name of the violator, the standards violated (but not the requirements) and the penalty amount. NERC would submit the remainder of the NOP, containing details on the violation, mitigation activity and potential vulnerabilities to cyber systems, as a non-public attachment, for which it would request CEII designation.
The only time a CIP NOP identified the violator was a 2011 case involving the Southwestern Power Administration, a federal power marketer (NP11-238). “The identity of the entity in this particular case was material to the resolution of the matter, as the entity had asserted a defense regarding the extent of the commission’s authority to impose a monetary penalty on a federal entity,” the paper said.
The staffs said separating public and non-public information will improve efficiency “because the information that would be made available to the public is readily identified and set forth in a cover letter. Perhaps more significantly, there is less opportunity for errors, including the inadvertent disclosure of potential CEII in the preparation and submission of CIP NOPs with line-by-line redactions.”
“The public identification of the CIP violator may result in increased hacker activity such as scanning of cyber systems and possible phishing attempts,” the staffs acknowledged. “However, the joint staffs believe that the limited information provided in the proposed cover letter would not provide an adversary with insights on the nature of the CIP violation or related cyber vulnerabilities, processes or procedures that could be used for an informed, focused attack on the violator’s cyber assets.”
The staff notice seeks comments on potential security benefits and security concerns from the new format as well as whether it will provide sufficient transparency to the public. Comments are due 30 days from the Aug. 27 notice.
FERC Commissioner Cheryl LaFleur said she was pleased the commission and NERC are reconsidering their policy, saying it was “an issue of growing controversy.” (See Reliability Conference: Deterrence or Collaboration?)
“It is important that we handle NOPs so as to avoid subjecting the bulk electric system to risk of a cyberattack once a vulnerability is identified,” LaFleur said in a statement. “At the same time, I believe state regulators, members of the public, and others have a legitimate interest in such violations, and we should seek to achieve as much transparency as we can consistent with protecting legitimate security interests.”
VALLEY FORGE, Pa. — PJM stakeholders last week expressed concern that transmission owners’ proposed procedure for eliminating vulnerabilities to “critical” transmission assets could undermine FERC-ordered transparency rules.
Critical infrastructure protection standard CIP-014-2 requires physical security plans for “highly critical” transmission assets — those “that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.” Less than 20 such assets — typically substations — were identified in PJM’s footprint.
The TOs say that the physical security enhancements required by the standard will not fully mitigate the risks associated with the loss of the critical substations. Thus, they want to propose new transmission facilities to provide redundancy so that the facilities are no longer critical. The proposed Tariff Attachment M-4 outlines a process to vet proposed CIP-014 mitigation projects (CMPs).
A PJM TO-proposed Tariff filing that skirts FERC-ordered transparency rules for replacing certain critical substations left other stakeholder sectors uneasy last week. | Pexels
The proposal was listed on the Markets and Reliability Committee’s Aug. 22 agenda as informational — meaning stakeholders don’t discuss it during the meeting. But it was opened for discussion at the request of the Consumer Advocates of the PJM States (CAPS) after some stakeholders wondered why the issue wasn’t vetted with involvement from all sectors.
“If the TOs aren’t taking an item like this into the Planning Committee, then what is the point of the PC?” CAPS Executive Director Greg Poulos asked, referring to the path stakeholders usually take to endorse Tariff filings. “It’s certainly something we need to discuss.”
According to PJM rules, replacing these CIP-014-2 assets — which count as a subset of supplemental projects — with new facilities must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed.
TOs suggest a vetting process in which PJM would confirm that the CMPs do not overlap with an existing baseline upgrade in the Regional Transmission Expansion Plan or harm system reliability. TOs would also consult state commissions, but public review of the project wouldn’t begin until after it is put into service. The TO zone where the project was built would assume 100% of the cost, according to the draft, keeping in line with other supplemental project rules. The filing would sunset after five years.
“There is a finite number of these facilities,” said Ken Seiler, PJM’s vice president of planning. “Our goal is to get those facilities off the list, so they are no longer critical. Our goal is to get it to zero and have no further facilities like this in our future going forward.”
Pulin Shah, director of transmission strategy and contracts for Exelon, told the MRC it was accepting stakeholder comments on the Tariff filing via email through Sept. 16.
“We do not have a particular time frame [for filing] because this is essentially a TO initiative,” he said. “The feedback process can impact next steps. If we receive no comment, we move to the next step in preparing a filing. If comments require an extensive level of responses, obviously that’s going to affect next steps.”
Many in the room, however, objected to the process through which the language was drafted and wondered how the sector would provide transparency into the concerns raised through the emailed comments.
“It could be viewed as a stepping stone to putting more supplemental projects behind a veil where there is no transparency to customers,” said Susan Bruce, an attorney representing the PJM Industrial Customers Coalition. “I think you can presume that you will get questions. My hope is that there is a process around [those questions] that is transparent to those of us who asked them.”
David “Scarp” Scarpignato of Calpine questioned the cost of replacing the facilities.
“How many dollars are you talking about here? That’s a pretty serious consideration,” he said. “If you are talking about super critical things … I’m thinking it’s in the lots of billions. Why is this not open to competition?”
Steve Herling, PJM’s executive consultant, said cost assumptions can’t be made at this stage, given that the proposed process is not yet in use and no solutions have been offered.
The New England Power Pool Reliability Committee last week indicated its displeasure with the re–evaluation of the fuel-security reliability review for Mystic Units 8 and 9, rejecting a motion that the review had been performed in accordance with ISO-NE’s market rules and planning procedures.
The motion, which required a two-thirds vote to pass, failed with only 26.65% in favor, with overwhelming opposition from the Generation, Transmission and Alternative Resources sectors. The Supplier and Publicly Owned Entity sectors were split, and the End User sector lacked a quorum.
ISO-NE sought to retain Mystic 8 and 9 for Forward Capacity Auction 13 after Exelon said in March that it would retire the entire 2,274-MW facility, including Mystic 7 and Mystic Jet, when its capacity supply obligations expire on May 31, 2022. FERC Approves Mystic Cost-of-Service Agreement.)
Interconnected system representation for 2023 (MW) used for a discussion of proposed tie benefits and ICRs with and without Mystic Units 8 and 9 | ISO-NE
For the re-evaluation for FCA 14, the RTO’s analysis looked at 18 scenarios and included increases in the amount of natural gas and fuel oil modeled and increases in the capacity values of some renewable resources.
The new analysis concluded that Mystic should continue to be retained because its retirement would violate two triggers: the use of load shedding in any hour under Operating Procedure 7 and the depletion of 10-minute reserves below 700 MW in an hour in the absence of a contingency in more than one LNG supply scenario.
[Editor’s Note: Speakers who raised objections to the analysis declined to be quoted on the nature of their concerns.]
The RTO’s assistant general counsel for markets, Christopher Hamlen, said the analysis was well vetted by the RC over the last year, so the methodology employed for the re-evaluation should have come as no surprise.
Norm Sproehnle, the RTO’s manager for outage coordination, said four generators that submitted retirement delist bid requests for FCA 14 — Yarmouth 1 (summer capacity of 50 MW), Yarmouth 2 (48 MW), Ipswich Diesels (9.3 MW) and Pinetree Power (16.9 MW) — did not need to be retained for fuel security.
Transmission operability analyses also found the resources could retire because none resulted in voltage or thermal criteria violations, said Abimael Santana, senior engineer in system planning.
The RC voted unanimously that the analyses for the four resources were in accordance with the market rules and planning procedures.
ICAP Requirements and Tie Benefits
The RTO’s manager of resource studies and assessments, Peter Wong, presented a review of the installed capacity requirements (ICR) and tie benefits for capacity commitment period 2023/24 (FCA 14), with and without Mystic 8 and 9.
For FCA 14, including or excluding the units in the New England resource mix will change the total tie benefits to New England by 30 MW, he said.
FCA 14 tie benefits assumptions for the calculation of the ICR-Related Values will be 1,940 MW for the scenario including the units, and 1,910 MW for the scenario excluding them.
Comparison of tie benefits results for FCAs 13 and 14 | ISO-NE
Hydro-Québec interconnection capability credits for FCA 14 for the “including Mystic” scenario will be 941 MW, while for the “excluding” scenario will be 943 MW, he said.
Assuming RC approval Sept. 25 and Participants Committee approval Oct. 4, the RTO plans to file with FERC by Nov. 5 ICR-related values for FCA 14, both including and excluding Mystic 8 and 9, Wong said.
The RTO will be sharing additional results with the NEPOOL Power Supply Planning Committee on Thursday.
FCM Planning Procedures
ISO-NE Director of Transmission Strategy and Services Al McBride revisited the topic of moving recently developed changes to Planning Procedure 10 (PP10) to the Tariff to support the Forward Capacity Market, as discussed at the combined RC and Transmission Committee meeting in July. (See “Modifying Interconnection Procedures,” NEPOOL RC/TC Briefs: July 16-17, 2019.)
McBride said the RTO is proposing to create a new section in the Open Access Transmission Tariff for the PP10 provisions. Changes include methodologies to update the levels of interconnection service for generators after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the FCM.
If approved by NEPOOL committees in September and October, and by the PC on Nov. 1, the changes would take effect in January 2020, he said.
The PP10 revisions will become effective after the proposed Tariff revisions are accepted by FERC and become effective, McBride said.
Revising Operating Procedure 14E
The RC voted to recommend that the PC support revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.
Jerry Elliott, a principal analyst in system operations at ISO-NE, presented the proposed revisions, which the PC will vote on at its Sept. 13 meeting.
Elliott also presented proposed revisions to OP-19, for a future vote. They would add the use of phase shifting transformers and adjustments of reactive flow to normal system actions performed by the RTO and each local control center to ensure transmission reliability.
In addition, he notified the RC of changes to OP-19 Appendix K to reconcile National Grid and NSTAR operating voltage limits with Master/Local Control Center Procedure 15 Attachment H – Voltage System Operating Limit Identification Procedure.
ISO-NE Lead Operations Analyst Kory Haag presented proposed revisions to OP-23 Appendix H, for a vote in September. They would clarify the data that are required for reactive capability test requests. The proposed effective date is in October 2019.
An LNG pipeline at Entergy’s Distrigas LNG Terminal in Everett, Mass. | Distrigas LNG
Maine Dominates PPAs
The RC approved several proposed plan application (PPA) notifications for solar and wind generation, as well as related transmission upgrades, most of them in Maine.
The committee voted to recommend to ISO-NE that the following projects will not have a significant adverse effect on the stability, reliability or operating characteristics of the transmission facilities of the applicant, the transmission facilities of another transmission owner or the system of a market participant:
Central Maine Power to install the 7.2-MW BD Solar Augusta solar array in Augusta, Maine, and interconnect it to the Blair Road Substation, with a proposed in-service date of Sept. 1, 2020.
CMP to install the 9.2-MW BD Solar Oxford solar array in Norway, Maine, and interconnect it to the Oxford Substation, with a proposed in-service date of Sept. 1, 2020.
NextEra Energy Resources to install the 75-MW Dawn Land Solar project in Washington County, Maine, as well as a transmission application to install a station transformer at the Deblois Substation to interconnect the solar array. Proposed in-service date is May 31, 2022.
Emera Maine to construct a new 115-kV substation and expand the Deblois Substation, adding one 115-kV breaker at the new substation and four 115-kV breakers at Deblois; adding 13.4 miles of 115-kV transmission line from the new substation to the Deblois substation; a new transformer and three new breakers at the new substation; and other associated transmission work. The proposed in-service date is May 31, 2022.
Con Edison Energy to replace the existing automatic voltage regulation on the Schiller CT 1 with a Basler DECS-250 digital pilot exciter. Proposed in-service date is in September 2019.
NextEra to install the 20-MW Randolph Center solar array in Randolph, Vt., and interconnect it to the Randolph Center 46-kV substation, with a proposed in-service date of Nov. 1, 2021.
SWEB Development to install the 20-MW Silver Maple wind farm in Penobscot County, Maine, and interconnect it to the Randolph Center 46-kV substation and to the Silver Maple four-breaker ring bus substation, with a proposed in-service date of Dec. 16, 2020.
Emera Maine to install a four-breaker ring bus substation in Penobscot County for the Silver Maple project, with a proposed in-service date of Oct. 1, 2020.
NextEra to install the 50-MW Chariot Solar facility in Hinsdale, N.H., and interconnect it to the 115-kV line between the Vernon Road Tap and Vernon Road Substation. The proposed in-service date is Nov. 1, 2023.
NextEra to build a new 115-kV three-breaker ring bus substation in Hinsdale to interconnect the solar project (proposed in-service date Oct. 1, 2021), as well as to install a station transformer that interconnects to the new substation, with a proposed in-service date of Sept. 27, 2023.
Competitive Tx RFP
ISO-NE Transmission Planning Director Brent Oberlin led the fourth discussion at the RC of competitive transmission solicitation enhancements. The package of changes being presented at the RC and TC includes proposed clarifications to Attachment K of section II of the Tariff, the draft Selected Qualified Transmission Project Sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.
The focus of the discussion with the RC was on the changes to the Tariff in section III.12.6 and the definitions in section I.2.2. Oberlin said that no comments had been received since the RC meeting in July, so the language remains unchanged from what had been presented previously.
Oberlin also said ISO-NE is still looking to act on the issue at the RC meeting in September.
Based on the results of the 2028 Boston Needs Assessment, the RTO plans to issue its first solicitation for a competitively developed transmission solution in December 2019.
Tx Cost Allocation
The RC voted unanimously to recommend that ISO-NE approve pool-supported costs estimated at $28.1 million for New England Power to replace 345-kV structures on the 303 and 3520 lines in Massachusetts.
NEP will replace 126 of 142 structures on the 303 line from Berry Street Substation to the ANP Bellingham Station and on the 3520 line from ANP Bellingham Station to the West Medway Substation because of asset conditions and installation of optical ground wire (OPGW) on both lines.
The committee accepted that none of the costs associated with the upgrade are considered localized costs.
Capacity Cost Compensation
The RC voted unanimously to recommend that ISO-NE approve two dynamic reactive resources as meeting the capacity cost compensation program (CCCP) eligibility requirements defined in the Tariff.
The resources, Canal 3 (Asset ID No. 38310) and Lisbon Resource Recovery (Asset ID No. 462), were recommended to have their qualified resource recovery designation to be effective Sept. 1.
Consent Agenda
The RC did not vote on its consent agenda that included one level 1 and 50 level 0 PPA notifications for solar generation, with 25% of the projects paired with battery storage.
One stakeholder noted the large number of hybrid solar/storage projects and wondered if ISO-NE was keeping tabs on the amount of energy storage being paired with solar each month.
McBride said the RTO has not been keeping that statistic separately but would consider the request. RC Chair Mariah Winkler said it appeared to be an issue of categorization.
Winkler said that the RTO would bring a revised consent agenda to the RC next month.
VALLEY FORGE, Pa. — PJM stakeholders last week expressed concern that a proposed Tariff filing by transmission owners could undermine FERC-ordered transparency rules for certain supplemental projects.
Consumer Advocates of the PJM States (CAPS) asked the Markets and Reliability Committee last week to open up discussion on the agenda item that was originally listed as informational — meaning stakeholders don’t discuss it during the meeting — after some wondered why a Tariff attachment that dealt with “critical” transmission assets wasn’t vetted with involvement from all sectors.
A TO-proposed Tariff filing that skirts FERC-ordered transparency rules for replacing certain critical substations left other stakeholder sectors uneasy last week. | Pexels
“If the TO’s aren’t taking an item like this into the Planning Committee, then what is the point of the PC?” CAPS Executive Director Greg Poulos asked, referring to the path stakeholders usually take to endorse Tariff filings. “It’s certainly something we need to discuss.”
The attachment in question, developed by multiple TOs, outlines a process to vet transmission system enhancements designed solely to remove critical assets — typically substations — from the CIP-014-2 list, which contains fewer than 20 assets within the PJM footprint. NERC reliability standards deem these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”
According to PJM rules, replacing these CIP-014-2 assets — which count as a subset of supplemental projects — with new facilities must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed.
TOs suggest a comprehensive vetting process that involves analysis and confirmation from PJM that projects capable of removing the assets from the CIP-014-2 list do not overlap with an existing baseline upgrade in the Regional Transmission Expansion Plan nor do they harm system reliability. TOs will also consult state commissions, but public review of the project won’t begin until after its put into service. The TO zone where the project was built will assume 100% of the cost, according to the draft, keeping in line with other supplemental project rules. The filing will sunset after five years.
“There is a finite number of these facilities,” said Ken Seiler, PJM’s vice president of planning. “Our goal is to get those facilities off the list so they are no longer critical. Our goal is to get it to zero and have no further facilities like this in our future going forward.”
Pulin Shah, director of transmission strategy and contracts for Exelon, told the MRC it was accepting stakeholder comments on the Tariff filing via email through Sept. 16.
“We do not have a particular time frame [for filing] because this is essentially a TO initiative,” he said. “The feedback process can impact next steps. If we receive no comment, we move to the next step in preparing a filing. If comments require an extensive level of responses, obviously that’s going to affect next steps.”
Many in the room, however, objected to the process through which the language was drafted and wondered how the sector would provide transparency into the concerns raised through the emailed comments.
“It could be viewed as a stepping stone to putting more supplemental projects behind a veil where there is no transparency to customers,” said Susan Bruce, an attorney representing the PJM Industrial Customers Coalition. “I think you can presume that you will get questions. My hope is that there is a process around [those questions] that is transparent to those of us who asked them.”
David “Scarp” Scarpignato of Calpine questioned the cost of replacing the facilities.
“How many dollars are you talking about here? That’s a pretty serious consideration,” he said. “If you are talking about super critical things … I’m thinking it’s in the lots of billions. Why is this not open to competition?”
Steve Herling, PJM’s executive consultant, said cost assumptions can’t be made at this stage, given that the proposed process is not yet in use and no solutions have been offered.
RENSSELAER, N.Y. — NYISO said last week that several of its market design projects are behind schedule, leading some stakeholders to question whether the ISO has taken on more initiatives than its staff can handle.
A joint meeting of the Installed Capacity (ICAP) and Market Issues working groups Wednesday heard updates on the 2019 capacity and energy market design projects and efforts to integrate distributed energy resources.
Capacity Market Projects
Michael DeSocio, NYISO’s senior manager for market design, said a study on fuel and energy security “is slightly behind schedule due to additional time taken in vetting assumptions, methodology and results.” Analysis Group reviewed preliminary results of the study with stakeholders Aug. 2, and the ISO expects it to complete the final report before the end of the year.
NYISO expects to present a complete market design and associated Tariff revisions this quarter on a proposal to refine the eligibility and energy delivery requirements of external capacity suppliers.
The tailored availability metric project is taking longer than originally planned, but the ISO expects to present a market design concept this quarter. The proposal will be based on analysis done for availability-based resources using the equivalent forced outage rate demand (EFORd) to determine the seasonal derating factor (AEFORd).
Preliminary results of a study on fuel and energy security in NYCA show a scenario in New York City with no disruptions and no emergency actions. | Analysis Group
The EFORd is the portion of time a unit is in demand but is unavailable because of forced outages and derates. NYISO believes that peak months should be weighted more heavily in the AEFORd calculation.
Analysis Group has been selected as the independent consultant for the 2019/20 demand curve reset project and kicked off the discussion at the ICAP/MIWG meeting Friday.
DeSocio said the competitive entry exemption for additional capacity resource interconnection service (CRIS) is slightly delayed but that a complete market design should be delivered this quarter, along with Business Issues Committee and Management Committee votes on it and related Tariff revisions.
An initiative aimed at revising market rules to repower aging generators, particularly in New York City, and ease barriers to entry to new generators also is slightly delayed, but the ISO still anticipates completion this year.
Current status of NYISO 2019 market projects | NYISO
DER Market Design
NYISO’s work on projects related to DERs is mostly behind schedule, including a pilot demonstration program and efforts to enable DER technology and develop a participation model.
“It seems like a lot of the projects are slightly behind schedule,” said Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers. “We’d certainly rather get to the right outcome than to the fastest outcome, but does the ISO have too many projects going?”
“I would appreciate a shorter project list,” DeSocio said. “We’re about at our limit of developing new proposals.”
DeSocio said enabling technology for DER “started as an effort thinking about the quantity of resources we’d need to participate in the market and how to minimize some of the overhead involved in getting DERs into the market.”
NYISO is exploring secure ways to use the Internet to ease DER integration, but the initiative is behind schedule because of delays with the DER model market design, although the ISO made a Tariff filing with FERC to establish a new aggregation participation model in June, DeSocio said.
He said the ISO will share results from the first round of pilot projects this year and begin looking at additional projects early in the fourth quarter. It plans to evaluate the feasibility of a second round of pilot projects in early 2020.
Energy Market Projects
The most prominent of the energy market design projects is the effort to price carbon into the wholesale electricity markets. An Analysis Group study on carbon pricing, previously expected to be completed in August, was delayed because of additional analysis requested by the NYISO Board of Directors.
CEO Rich Dewey told the Management Committee at the end of July that the board wants to ensure that the study captures all the impacts of the Climate Leadership and Community Protection Act (A8429), which requires the state to get 70% of its power from renewables by 2030 and eliminate carbon emissions from the power sector by 2040. (See “Carbon Study Delay to Include New Energy Law,” NYISO Management Committee Briefs: July 31, 2019.)
New York Gov. Andrew Cuomo (right) flanked by former Vice President Al Gore, signs the Climate Leadership and Community Protection Act on July 18. The law requires the state to get 70% of its power from renewables by 2030 and eliminate carbon emissions from electricity production by 2040. | New York Governor’s Office
DeSocio said the ISO now expects Sue Tierney of Analysis Group to present results of the study in early October.
NYISO also is behind on constraint-specific transmission shortage pricing, which it had hoped would be completed by the second quarter this year. DeSocio said the ISO is considering whether it is prudent to request a stakeholder vote now given other project priorities and implementation timing.
“Given other priorities, it has taken longer to get us to the point where we can have a discussion and vote on the Tariff. … Considering the pressures to integrate energy storage and DER by 2021, we are considering when to re-engage with those discussions,” he said.
“This effort should not keep getting delayed,” responded Mark Younger of Hudson Energy Economics. “Maybe you need more people.”
FERC ordered the ISO to submit a compliance filing on enhanced fast-start pricing by Dec. 31 and to deploy it by the end of 2020.
DeSocio said the ISO is working with market participants and the External Market Monitor on a methodology for amortizing commitment costs of fast start resources when determining locational-based marginal prices and should be bringing a proposal to stakeholders “any day.”
NYISO also is continuing to research the need for load pocket operating reserves within New York City and hopes to complete a market design that meets the objective in the third quarter, he said. Market participants in March approved the creation of a Zone J reserve region, which was implemented June 26.
The project to develop reserves for resource flexibility is on schedule, and the ISO will present a proposal for discussion by the end of the third quarter, DeSocio said.
Finally, a study on ancillary service shortage pricing is on schedule to be completed by year-end, he said.
Modifying CRIS Expiration Rules
The working groups also discussed NYISO’s proposed tightening of CRIS expiration rules, which would prevent existing facilities from retaining CRIS if they do not enter the NYISO ICAP market for three years.
Associate Market Design Specialist Sarah Carkner presented NYISO’s proposal to modify the CRIS expiration rules and said the ISO decided earlier this year to discuss the issue separately from the class year redesign project.
The ISO proposes three distinct changes to CRIS expiration rules:
Start of the CRIS expiration “clock” would be when the facility begins operation.
Load modifiers not participating in the NYISO-administered markets would be CRIS-inactive. Load modifiers are DERs that do not actively participate in the NYISO’s markets but instead are used by load-serving entities to reduce the power they must procure from the ISO.
A resource exporting capacity would not be inactive under CRIS even if it has not sold capacity in New York.
“The rule would be effective a few years after FERC acceptance to allow resources currently acting as load modifiers, and wishing to maintain their CRIS, an opportunity to enter the capacity market,” Carkner said.
David Clarke, director of wholesale market policy for Long Island Power Authority’s Power Supply Long Island, said his company favored the status quo. He asked if this was a modeling issue.
Zachary T. Smith, NYISO manager for capacity market design, said that “because the NYISO doesn’t have visibility of load modifiers not participating in NYISO-administered markets, we’re not sure if those resources are even generating anymore.”
Regarding treatment of exporters, DeSocio said, “We’re trying to create reciprocity with our neighbors … to make sure we’re being consistent in the region.”
VALLEY FORGE, Pa. — Interim PJM CEO Susan J. Riley told the Markets and Reliability Committee on Thursday that work continues in the Financial Risk Mitigation Senior Task Force to overhaul credit policies in the wake of the GreenHat Energy default.
“We want to be sure that we are not making one-off changes that have unintended consequences,” she said. “I’m sure you can appreciate [the need for] … establishing collateral rules that protect our members.”
Nigeria Poole Bloczynski, PJM’s newly hired chief risk officer, addressed the task force during its Aug. 15 meeting and said that while the GreenHat default — which could cost members more than $430 million — prompted the review, the forthcoming changes will benefit “all of PJM’s markets.” (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
“While there’s some low-hanging fruit, what I want to do is take a very thoughtful approach as it comes to pulling together the credit-risk policy, because I think we can tackle some issues that not only relate to FTRs, but to the broader market that we participate in,” she said in a press release. She also said the RTO must monitor and “take active measures to mitigate risk exposures that are generated by each participant.”
Riley also told the task force that feedback from members remains paramount in structuring effective reforms.
“We’ll propose certain things that we feel are important, but we really want your input and your thoughts on their viability, on how these things affect your companies [and] your businesses,” she said. “We think we’re doing the right thing and feel pretty strongly — but again, we welcome your input.”
Non-retail BTM Generation Vote Delayed
Stakeholders deferred a vote on manual revisions that clarify updates to PJM’s non-retail behind-the-meter generation (NRBTMG) rules, opting for more time to discuss elements of the proposal regarding community solar and net energy metering.
Exelon led the effort for delay after requesting to remove the voting item from the consent agenda. Sharon Midgley, director of wholesale development for Exelon, said her company could “benefit from another month of discussion.” Public Service Enterprise Group, the PJM Public Power Coalition and Duquesne Light Co. agreed.
The revisions to Manuals 13 and 14D, which address the reporting, netting and operational requirements of NRBTMG, are intended to ensure member and PJM responsibilities, processes and procedures are clear and adequately captured, said Terri Esterly, PJM’s senior lead engineer for capacity market operations. (See “BTM Generation Clarifications,” PJM OC Briefs: Aug. 6, 2019.)
NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.
Midgley said Exelon approves of the concepts and reporting requirements outlined in the manual change but is still reviewing differences in the application of the rules — specifically whether community solar programs and aggregate net energy metering are within scope.
“Exelon doesn’t think they fall into a ‘non-retail behind the meter generation’ category, and PJM is interpreting these types of programs as being in scope,” she said. “If in scope, these programs would need to respond to certain emergency procedures, and we are questioning if this is appropriate.”
Fuel Security Charter Revisions Endorsed
The MRC unanimously endorsed a revised charter for the Fuel Security Senior Task Force, which will allow members to progress to phase 2 and bring its recommendations to the Dec. 19 MRC meeting — three months after its original deadline of September.
Tim Horger, director of energy market operations for PJM, said the modified timeline streamlines the process and keeps stakeholders out of a “messy” situation should recommendations scheduled for next month not win endorsement.
The task force is expected to deliver recommendations to the MRC on whether market, operational or planning changes are needed to ensure “fuel/energy/resource” security. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)
Manuals Endorsed
Stakeholders endorsed the following manuals:
Manual 10: Pre-Scheduling Operations, regarding generator outage reporting. The changes include clarifications for outage ticket end dates for deactivations and outage ticket requirements for black start service.
VALLEY FORGE, Pa. — Stakeholders remain displeased with what they call the vagueness of PJM’s revised gas contingency filing, saying it will punish resources that deliver additional flexibility when the grid needs it most.
Thomas DeVita, PJM senior counsel, told the Markets and Reliability Committee that staff will file the revised version at PJM MIC Briefs: Aug. 7, 2019.)
Vector Pipeline | DTE Energy
The commission also argued that the conditions for switching belong in the Tariff — not just manuals — and gave PJM a chance to revise the proposal over the spring and summer.
DeVita said Thursday the new filing replaces the defined costs with a direct “but for” test to “encompass all costs that would not have been incurred ‘but for’ the generator’s compliance with the switching instruction.”
“The ‘but for’ test is immensely broad. … There are a wide range of potential costs that are not recoverable but could be under that extremely broad language,” said Joe Bowring, PJM’s Independent Market Monitor.
Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, argued that despite PJM’s assertion that it has the authority to direct pipeline switches, there’s no sufficient way to reward those that respond. He said the proposed Tariff language provides a “limited opportunity” to recover costs and may discourage resources from providing that extra flexibility in order to minimize their financial risk.
“The cost recovery PJM has proposed is fraught with holes that will result in resources being unable to recover the legitimate costs they incur in complying with PJM’s mandate,” he said. “But even if full cost recovery is attainable, the resource is left without any incentive for providing the flexibility.”
Stakeholders also questioned where PJM’s authority will end and worried that approving such broad cost recoveries could lead the RTO down a “slippery slope.”
“My concern is, tomorrow PJM might be directing a generator to give its spare parts to a neighbor,” O’Connell said. “There must be a bright line [in the sand] … and we must never cross that line.”
PJM argued that both FERC’s invitation to rewrite the proposal and existing manual language confirms that it has the authority to order pipeline switches.
“I think we are more than happy to go back and review the discussions on authority that were had when those provisions were put in place,” said Stu Bresler, senior vice president of markets and planning. “There was discussion on this when the manual language was developed. The fact of the matter is it could occur; our thought was, to get some certainty around what would happen regarding compensation is a good thing.”
