Page 1203 – RTO Insider

August 26, 2019

NEPOOL Reliability Committee Briefs: Aug. 20, 2019

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.)

NEPOOL — 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.

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.

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.

— Michael Kuser

August 26, 2019

PJM TO Tariff Filing Stirs up Transparency Concerns

By Christen Smith

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.

PJM — 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.”

Susan Bruce, PJM Industrial Customer Coalition | © *RTO Insider*

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.”

PJM — David “Scarp” Scarpignato, Calpine | © *RTO Insider*

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.

August 26, 2019February 12, 2025

NYISO Behind Schedule on Market Design Projects

By Michael Kuser

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 kick ed 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.”

August 25, 2019

PJM MRC Briefs: Aug. 22, 2019

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.)

PJM’s Markets and Reliability Committee met Aug. 22 at the Valley Forge Conference and Training Center. | © *RTO Insider*

“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 revision s 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.
Manual 11: Energy & Ancillary Services Market Operations and Manual 18: PJM Capacity Market, to bring the RTO into compliance with PJM MIC Briefs: July 10, 2019.)
Manual 18B: Energy Efficiency Measurement & Verification, resulting from a periodic review.

– Christen Smith

August 25, 2019

Stakeholders: PJM Gas Contingency Filing too ‘Vague’

By Christen Smith

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.)

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.

Thomas DeVita, PJM senior counsel — Thomas DeVita, PJM | © *RTO Insider*

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.”

August 25, 2019

MISO Recommending 1st Storage-as-Tx Project

By Amanda Durish Cook

MISO is poised to recommend its first-ever storage-as-transmission project to ease reliability issues in central Wisconsin, though the RTO doesn’t yet have rules to govern the project’s operation.

The RTO last week said it reviewed American Transmission Co.’s Waupaca area energy storage project against an alternative wires solution also submitted by the company. MISO concluded that while both projects improved reliability, a comparison of life cycle costs proved the storage project more cost-effective. Consequently, the project is set to be included in MISO’s 2019 Transmission Expansion Plan (MTEP 19) for approval in early December.

The 2.5-MW/5-MWh battery project is expected to cost $8.1 million and be in service at the end of 2021. ATC’s alternative 115-kV double circuit rebuild would have cost $11.3 million.

MISO said its preliminary recommendation is dependent on MISO Firming Up 1st SATA Ruleset.)

“There’s a big asterisk on” the project, MISO expansion planner James Slegers told stakeholders during a conference call Friday.

MISO storage-as-transmission project — ATC SATA project map | *MISO*

ATC plans to automate the storage facility, which will be triggered only on a post-contingency basis. ATC’s Jim Hodgson said costs of battery degradation are all included in the company’s estimated operations and maintenance costs and based on “the best available information.” The storage project also includes two new capacitors.

The company doesn’t expect the battery to be used often but notes it would have to cycle daily to keep in good condition. ATC is working off the assumption that the battery will last 20 years. The company also expects no public impact on rights of way. (See MTEP 19 Could Yield First MISO SATA Project.)

“First and foremost, it’s a reliability asset,” ATC’s Bob McKee told MISO and stakeholders.

ATC’s Waupaca area contains a local 69-kV system supported by a nearby multi-segment 115/138-kV transmission line. The area is at risk of voltage collapse if it experiences a double contingency or outage in conjunction with prior maintenance. When both ends of the 115/138-kV supply line are out of service, the system cannot sustain local loads at certain levels, Slegers said.

ATC currently uses an operating guide to open line segments to serve load radially on the 69-kV system after load levels reach a certain point and after a first outage. While the operating guide allows loads to be served after a second contingency, it places up to 114 MW of load at risk of disconnection, according to MISO. The battery is designed to operate after a second contingency.

MISO Manager of Expansion Planning Lynn Hecker said the RTO has worked closely with ATC to understand the operation of the battery and the maintenance costs.

RTO staff said the battery wouldn’t negatively impact the dispatch of the four nearby generation projects finishing the final phase of the generator interconnection queue. However, MISO hasn’t yet determined the network upgrades the projects might require because the projects entered the definitive planning phase in spring 2018.

MISO will post a draft MTEP 19 report on Sept. 16. So far, the RTO is positioned to recommend 529 new projects at $4.4 billion. The newest estimate is higher than those released in spring. (See MTEP 19 Revealing High Price Tag.) If approved, this year’s buildout package will be MISO’s most expensive. Last year, the RTO cleared a $3.3 billion, 442-project MTEP 18.

August 25, 2019

MISO to Host Hybrid Projects Workshop

By Amanda Durish Cook

MISO will host an in-depth workshop this fall on how to incorporate generation projects that draw on more than one fuel source.

The workshop, tentatively planned for Oct. 8, will focus mostly on intermittent generation projects paired with electric storage. The workshop idea materialized during a Steering Committee call Thursday, when members of the former Energy Storage Task Force presented a list of hybrid resource topics to be assigned to stakeholder groups for developing possible Tariff changes and Business Practices Manuals.

The list of 22 topics regarding hybrid generators is the pièce de résistance of the ESTF, which sunset in June after identifying energy storage topics that MISO and stakeholders should focus on in order to integrate storage into the RTO’s markets. The list of hybrid considerations was the final document the group produced. (See “Next up: Hybrid Resources,” MISO Undecided on Amending Storage Plan.)

Currently, MISO models hybrid resources separately for each fuel source. The ESTF said addressing its list would help “facilitate non-discriminatory market participation.”

Committee members were initially daunted by the length of the list until Chair Tia Elliott suggested the all-stakeholder workshop. The committee is responsible for routing new grid topics to the appropriate MISO stakeholder committee.

Among other ideas, the ESTF wants MISO to begin considering: capacity accreditation; ensuring hybrid output doesn’t exceed interconnection service levels; addressing state of charge; whether to allow separate or dual metering; how the RTO’s must-offer rule would apply; participation in ancillary services; and asset registration.

The Planning Subcommittee is already considering how a hybrid resource will be studied in the generator interconnection process, one of the ESTF’s priorities. (See MISO Queues up Interconnection Options.)

“Hybrid storage resources are under active development and could be online in MISO in the near term. Prompt resolution to the … issues is necessary not only to ensure accurate assessment of the business case for market participants, but also to ensure these resources are appropriately participating in the market under the required rules and structures,” the ESTF said.

The ESTF has requested the hybrid topics receive immediate attention from the Market Subcommittee, Resource Adequacy Subcommittee, Planning Advisory Committee and Reliability Subcommittee. Former ESTF Chair John Fernandes said many of the issues couldn’t wait until MISO’s 2020 Integrated Roadmap list of market improvements, explaining that hybrid projects are already in the works in the RTO’s footprint. He pointed to Entergy’s proposed 100-MW hybrid solar-and-storage project, currently before the Arkansas Public Service Commission. The project is expected to enter service by 2021.

“We do want to create a little bit of urgency around this,” Fernandes told Steering Committee members.

Clean Grid Alliance’s Rhonda Peters seconded Fernandes’ call for urgency and urged the committee to track the topics on the list to make sure stakeholder groups are actively tackling them.

“This issue list is comprehensive, and it shows how much work the task team put into it,” MISO Market Design Adviser Bill Peters said.

August 25, 2019

FERC Denies Shell, ODEC GreenHat Settlement Role

By Christen Smith

Shell Energy and Old Dominion Electric Cooperative failed to make their case that they belong at the GreenHat Energy settlement table, FERC said in denying the companies’ rehearing requests Thursday.

FERC said the companies’ argument that they are “uniquely situated” in the proceeding and that their late intervention would not “unduly burden or prejudice any party” was “unpersuasive” (ER18-2068).

“We do not find that failing to grant late intervenors party status will necessarily result in a settlement that is not ‘fair and reasonable and in the public interest,’” FERC said. “Should the parties reach settlement in this proceeding, the commission will review the terms of that settlement and determine whether such settlement meets the relevant standard.”

Shell’s request for rehearing argued that FERC erred when it dismissed more than a score of late-filed motions from intervenors seeking to participate in the unwinding of GreenHat’s financial transmission rights portfolio. GreenHat was declared in default in June 2018 after it failed to make good on its mounting losses. (See Shell Demands Seat at GreenHat Settlement Table.)

GreenHat Settlement — An independent consultants’ report said GreenHat’s trading “was conspicuous in that its positions were far larger and of longer tenor than those of other financial participants in the FTR market.” | *PJM*

On June 5, the commission gave FERC: PJM Settle Disputes Before GreenHat Hearing.)

Shell was among more than 20 petitioners that filed after the comment period for PJM’s request passed. FERC rejected the late filings, saying none demonstrated “requisite good cause for late intervention.”

Shell said a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners faces. It had explained that it entered into three bilateral contracts with GreenHat that involved transferring FTRs back and forth between the two companies. Liquidating the GreenHat portfolio “could substantially affect the amount sought by PJM from Shell for the guarantee and indemnification claim” the RTO placed on the portion that was transferred. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

“Shell Energy knew at the time PJM filed its waiver request that it had transactions with GreenHat that a commission ruling might affect,” FERC said. “Regardless of whether Shell Energy agreed with PJM’s request for waiver, it could have intervened timely to protect its interests.”

ODEC had said its late filing was nothing more than an “oversight” — an explanation the commission found lacking. It said ODEC’s interests in the case, which could set a precedent for financial defaults in RTOs, could be “sufficiently” represented by other timely intervenors.

“Old Dominion does not explain in seeking late intervention how other participants will not sufficiently represent this generalized interest, and there are, in fact, others who timely intervened on the basis they too would be impacted by the outcome of the proceeding,” FERC said. “Moreover, concern that adverse precedent may be created is not a persuasive basis for late intervention.”

August 25, 2019

Labor Dispute Stalls FirstEnergy Reorganization

By Christen Smith

A U.S. bankruptcy judge stalled FirstEnergy Solutions’ reorganization plan last week over unresolved contract disputes with workers at its Perry and Beaver Valley nuclear plants.

Judge Alan M. Koschik told lawyers for the utility that he cannot approve its reorganization plan — which includes shedding $3.6 billion in debt, cutting ties with FirstEnergy Corp. and possibly changing its name — until the issue is resolved. He set a status hearing for Sept. 10.

FES wants to renegotiate the terms of the collective bargaining agreements with the Utility Workers Union of America and the International Brotherhood of Electrical Workers that were originally approved by FirstEnergy because the company claims it cannot afford the pension benefits post-bankruptcy. (See FES Seeks Bankruptcy, DOE Emergency Order.)

A U.S. bankruptcy judge stalled FirstEnergy Solutions’ reorganization plan over unresolved bargaining contract disputes with workers at its Perry and Beaver Valley nuclear plants.

“We are pleased with the progress made in the hearings, which resolved substantially all non-labor-related issues pertaining to confirmation of our plan,” FES spokesman Tom Becker said in a statement Friday. “We remain focused on confirming the plan to exit bankruptcy by the end of 2019.”

In court documents filed earlier this month, Joyce Goldstein, attorney for both unions, argued that they had struck contracts that contain a “strong successorship” clause requiring FES to assume the terms of the agreements. Goldstein also noted that because Ohio lawmakers passed a bill to subsidize the state’s nuclear plants, FES will “have even more cash” on hand to pay benefits. (See Ohio Approves Nuke Subsidy.)

“There is no impediment to assuming the CBAs and providing benefits that mirror those currently provided, as has occurred eight times before,” Goldstein said, referencing FirstEnergy’s decision to assume bargaining unit contracts when it acquired other utility companies pre-split. FES “would simply prefer not to.”

Frank Meznarich, president of UWUA Local 270, applauded Koschik’s decision in a statement Friday, calling it a “significant victory for our members.” UWUA represents workers at the Perry nuclear plant, located 40 miles northeast of Cleveland along Lake Erie. IBEW Local 29 represents workers at the Beaver Valley plant near Pittsburgh.

“FES cannot escape bankruptcy without fulfilling its obligations to the individuals who maintain and operate these facilities,” Meznarich said. “Our members have been unwavering in their efforts to deliver power to ratepayers who rely on it and we expect FES to honor its legal obligations to our members.”

FES CEO John Judge wrote in an Aug. 18 column for The Columbus Dispatch that his company’s good faith negotiations have resulted in signed framework agreements at three of its five nuclear plants since March. He said the latest proposal submitted to the bargaining units at Perry and Beaver Valley include terms that preserve the wages, raises, work rules, medical, dental and paid time off benefits found in the existing contracts.

“The only open issue we have is retirement benefits after emergence, since we can no longer participate in the FirstEnergy Corp. pension plan at that time,” he said. “No retirement benefits earned prior to emergence will be taken away.”

Post-bankruptcy, FES plans to offer an “enhanced defined contribution plan” that matches 50 cents of each $1 contribution made by employees up to 6%. Employees with long tenures will receive additional contributions up to 9%, and those closest to retirement will be offered bridge payments to soften the blow of plan changes.

Judge said the program exceeds industry standards and serves as a “fair offer … since we kept other elements of the existing wages and benefits intact and all benefits earned to date will be paid.”

“Our power plants must compete with other unregulated power generators in what is a tough economic environment,” Judge said. “None of our competitors has started a new traditional pension plan or offer such a plan to new employees. Our proposal allows our plants to remain competitive, stay open and continue to employ the workers we rely on to operate those plants.”

August 25, 2019March 19, 2025

NEPOOL Transmission Committee Briefs: Aug. 21, 2019

New England Power Pool Counsel Eric Runge provided the Transmission Committee with an update on the hearing procedures in the proceeding under Federal Power Act Section 206 on network service formula rates (EL16-19-002).

FERC Rejects New England Tx Rate Settlement.)

The settlement proposed new rates and a new rate design for regional network service (RNS), local network integration transmission service (LNS) and point-to-point (PTP) transmission service for all the TOs in the region. It would have replaced the existing RNS and LNS rates with new formula rate templates and associated protocols.

FERC trial staff argued that the settlement was unfair because it would have set unreasonable rates and “contains fundamental defects.” Staff cited the TOs’ ability to conduct “extra-formulaic, ad hoc” ratemaking for all externally sourced inputs every year and over-recover certain plant costs.

The commission instituted the proceeding in December 2015, saying ISO-NE’s Tariff “lacks adequate transparency and challenge procedures” on the NETOs’ formula rates and that the network rates “lack sufficient detail” to determine how costs are derived and recovered.

Under a scheduling order approved Aug. 13, direct testimony from witnesses seeking changes to the existing rates is due Oct. 10, with answering testimony to defend the existing rate due Jan. 10, 2020. Rebuttal testimony responding to answering testimony is due March 2, and discovery requests must be submitted by March 12. A hearing is scheduled for April 27 through May 12. Oral arguments, if necessary, will be held Aug. 10 with an initial decision targeted for Sept. 21.

Runge said the commission could issue an order by the end of next year. The order, he noted, could be followed by rehearing requests.

Changing Interconnection Capability Following Partial Market Exits

Director of Transmission Strategy and Services Alan McBride led a d iscussion of ISO-NE’s proposed procedural changes to clarify how the RTO adjusts interconnection capability after partial market exits.

The RTO is drafting Tariff changes to collect in one place the rules now in three schedules and Planning Procedure No. 10 that detail how it updates interconnection service limits for generators. The rules would apply after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market. The changes, to be collected in a new section II.48 of the Tariff, also would apply to external elective transmission upgrades.

The changes include an exception process for reducing summer capacity without changing winter limits. The exception would allow generators to provide engineering information to the RTO to prove that the formula-based, proportional winter capability adjustments for a partial retirement do not accurately calculate their winter interconnection capability.

The RTO hopes to make the changes effective in January following approvals by the Reliability Committee in September, the TC in October and the Participants Committee in November.

Competitive Transmission Solicitation Enhancements

ISO-NE Director of Transmission Planning Brent Oberlin outlined proposed Tariff revisions to accommodate Order 1000 competitive transmission solicitations.

The RTO said the changes are needed because the selected qualified transmission project sponsor agreement (SQTPSA) did not specify that project modifications may be required under section I.3.9 of the Tariff and that failure to reach agreement on modifications may be grounds for termination. It also said changes were needed to Attachment K of the Tariff to consider system performance as an evaluation factor and specify that participating TOs must stop work on projects related to the upgrade of existing facilities once a developer has been selected as the “stage two” solution. It is also refining the definition of “localized costs” to make it consistent with the intent of the competitive process and differentiate it from asset condition projects.

Oberlin outlined several changes to the SQTSPA and Attachment K since the July TC meeting.

The TC will vote on the revisions Sept. 17 with a PC vote expected Oct. 4.

Cost Recovery for CIP Standard Compliance

ISO-NE’s Jonathan Lowell presented the RTO’s proposal for a cost recovery procedure for generators’ compliance with NERC’s critical infrastructure protection (CIP) standards. Generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits face higher CIP standards than “non-critical” generators, and the costs cannot be competitively offered and recovered through the energy and capacity markets.

Lowell said the RTO’s goal is to reduce the time and expense involved in the cost filings and provide guidance on cost identification and categorization while avoiding the need for reconciliation and true-up procedures. It will “emulate a ‘formula rate’ construct as much as possible,” Lowell said.

A new Schedule 17 will set out a procedure for generators to make FPA Section 205 filings to gain FERC approval of the costs. The proposed costs would be posted for at least a 60-day review period before the FERC filing, and there will be Webex or in-person briefings for interested stakeholders. The prefiling review is intended to result in uncontested FERC filings and definitive orders that the RTO can rely on for billing.

Range of study time frames for establishing interconnection reliability operating limits | NERC

The RTO will support “direct cost” categories identified in the Schedule 17 template. Generators would have to support other costs not covered by the template.

Once approved by FERC, ISO-NE will bill the costs over 12 equal payments over a year.

Lowell said the RTO has eliminated previous proposals for 24-month and 36-month amortization periods and differentiations for “recurring” and “nonrecurring” costs.

ISO-NE proposes costs be allocated to transmission customers based on monthly regional network load and monthly average through or out service. “Incremental CIP compliance costs are not a transmission cost, but it is correct and efficient to allocate these costs to transmission customers as beneficiaries,” the RTO said.

Charges will be separately identified on RTO customers’ monthly non-hourly charges statements.

In his own presentation, Eversource Energy’s Paul Krawczyk reiterated the company’s contention that “recovering these costs through transmission charges is inappropriate.” (See Eversource Balks at ISO-NE Plan on CIP Costs.)

Eversource, which had previously suggested several alternatives, is now proposing the costs be allocated to real-time load obligations.

The TC is expected to vote on the proposal at its Oct. 10 meeting with a PC vote Nov. 1.

— Rich Heidorn Jr.