Page 1274 – RTO Insider

March 5, 2019

FERC Reverses Waiver on SPP’s Z2 Obligations

By Tom Kleckner

FERC last week reversed a waiver it had previously issued to SPP on Attachment Z2 of its Tariff and directed the RTO to provide refunds of credit payment obligations, with interest (ER16-1341).

The commission ordered SPP to refund credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff.

SPP was seeking a retroactive waiver of its Tariff so that it could invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior to its April 2016 request. In its reversal Thursday, FERC found “the relief sought by SPP … is prohibited by the filed rate doctrine and the rule against retroactive ratemaking.”

SPP’s headquarters in Little Rock, Ark. | *WER Architects*

The commission approved the waiver request in a July 2016 order that set aside the one-year time limit. In November 2017, FERC denied a rehearing request by several stakeholders. (See “Z2 Waiver Upheld,” FERC Rejects SPP Change on Network Resource Upgrades.)

But FERC issued a voluntary remand of the waiver orders after Xcel Energy appealed to the D.C. Circuit Court of Appeals in January 2018. The commission’s reversal was prompted by the court’s June decision to uphold FERC’s order rejecting Old Dominion Electric Cooperative’s request for a waiver of Duke, ODEC Rebuffed on Polar Vortex Gas Refunds.)

FERC noted the D.C. Circuit has recognized the commission’s “‘broad remedial’ authority to remedy unjust outcomes.” But it said that exercising its authority under the Federal Power Act in this instance “would be inappropriate,” noting that the court in ODEC “highlighted that the commission cannot disregard for good cause or any other equitable grounds either the filed rate doctrine or the rule against retroactive ratemaking.”

Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.

An SPP spokesman said the company is reviewing the order and its options. It estimates the credit payment obligations for the historical period to be approximately $200 million.

Last week’s order requires SPP to file a report within 120 days detailing how it plans to make the required refunds and allows third parties to comment on the RTO’s proposal. “SPP shall not provide any refunds prior to the issuance of a further commission order directing refunds,” FERC said.

Xcel Energy upgrade project | em>Burns & McDonnell

Commissioners Cheryl LaFleur and Richard Glick, who reluctantly concurred with the decision, issued separate statements attached to the order.

“The financial impacts of today’s order will rightly be frustrating to those parties that would otherwise receive credits for the historic period, and the order provides an unfair windfall to those who benefited from those upgrades during the historic period but are not required to pay for them,” LaFleur wrote.

“This is a result that could have been avoided, and we should, where possible, take steps to prevent similar issues in the future. As today’s order notes, the New York Independent System Operator Inc. Tariff authorizes the commission to order changes to otherwise ‘finalized’ data and invoices. I join Commissioner Glick in encouraging SPP and other RTOs/ISOs to consider comparable revisions to their tariffs to avoid similarly inequitable outcomes in the future.”

March 5, 2019December 13, 2023

Texas PUC Briefs: Week of Feb. 25, 2019

Saying they want to move forward quickly with real-time co-optimization (RTC), Texas regulators approved a list of issues to be discussed during a summer workshop on the potential market change (Project 48540).

ERCOT staff have said it will take four to five years and about $40 million to implement RTC, under which energy and ancillary services are procured simultaneously every five minutes in the real-time market to find the most cost-effective solutions for both.

“I want real-time co-optimization moving forward, the sooner the better,” Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “We are hearing in my office that the more ERCOT’s operations staff learns about real-time co-optimization, the more excited they’re getting about the tools and benefits, as far as efficiencies not only in the market, but system efficiencies as well.”

The commission is asking stakeholders to file written comments on what value to set as the systemwide offer cap, what value to set for lost load and which ancillary services should be used in developing ancillary service demand curves, among other issues.

The PUC is scheduling the workshop in early June.

PUC Amends Preliminary Sempra-Sharyland Order

The commission adopted an amended preliminary order on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services (Docket 48929).

The order sets aside the prudence of investments in any assets for future rate cases and clears up inconsistencies involving allocation factors.

The applicants are seeking the PUC’s approval for the $1.37 billion worth of transactions, which were announced in October. The deals would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in Central, North and West Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest. (See Sempra, Oncor Deals Target Texas Transmission.)

A hearing on the merits is scheduled for April 10-12.

The PUC also:

a pproved $369.2 million in AEP Texas system restoration costs stemming from Hurricane Harvey in 2017 (Docket 48577); and
l evied a $68,000 administrative penalty against Southwestern Public Service for exceeding its system average interruption duration index value (Docket 48826).

PUC, Gas Regulator Call for Coordination

The PUC and the Texas Railroad Commission (TRC) issued a joint statement last week describing their efforts to prepare for the summer months by guiding coordination among natural gas pipelines, gas-fueled power plants, and utilities that service the pipelines, plants and other customers. The TRC has jurisdiction over natural gas utilities.

The agencies urged companies to finalize their coordinated preparations for the summer, maintain clear lines of communication as the summer progresses and participate in ERCOT’s Gas-Electric Working Group. Natural gas fuels about half the generation in ERCOT.

“Texas has more than enough natural gas to fuel power generation,” TRC Chair Christi Craddick said. “We must make sure it can get where it’s needed, when it is needed, and that requires coordination between gas pipelines companies, electric generation facilities and electric utilities.”

PUC spokesman Andy Barlow said the agencies’ goal is to “guide maintenance scheduling to reduce situations in which pipeline maintenance might interrupt the flow of gas to Texas gas-fired plants and/or electricity flow to pipeline facilities.”

Texas Senate Confirms Commissioners

The Texas Senate on Wednesday unanimously confirmed all three commissioners, who were appointed by Gov. Greg Abbott between legislative sessions. The commissioners have been serving between eight and 17 months.

Commissioner Shelly Botkin’s term expires on Sept. 1, with Walker’s expiring in 2021 and Commissioner Arthur D’Andrea’s in 2023.

— Tom Kleckner

March 3, 2019

MISO Reliability Subcommittee Briefs: Feb. 27, 2019

CARMEL, Ind. — In the wake of its January grid emergency, MISO has pledged to further study generation cutoffs in extreme temperatures and how it can best account for voluntary load curtailments in load forecasting.

MISO said its Jan. 30-31 emergency was in part triggered by a greater-than-expected drop in wind generation, with emergency demand difficult to predict as schools and businesses closed for the day and millions of energy consumers lowered their thermostats during the event in response to utility requests. (See MISO Details ‘Uncertainty ’ Behind Winter Max Gen Event.)

MISO said temperatures in its North region were more than 6 degrees Fahrenheit below those during the 2014 polar vortex. Forced outages surpassed 20 GW, while total outages and derates took more than 35 GW of generation offline. Although the RTO didn’t call on its neighbors for imports, its higher emergency prices attracted more than 5 GW of imports. Over the two days, the RTO exceeded $18 million in uplift charges, on par with other severe cold snaps. Load-modifying resource (LMR) use peaked at almost 3.9 GW on Jan. 30.

“Basically, it was unprecedently cold in MISO,” Director of Central Region Operations Ron Arness said during a Reliability Subcommittee meeting Wednesday. “Temperatures were colder than any since the existence of MISO, and we suspect that’s why wind generation was cutting off. … Even though the temperatures are abnormal, we should have this cutoff information so we can make good assessments about what generation is forecasted for the next day.”

IPL crews restoring power Jan. 31 | *Indianapolis Power and Light*

Arness said MISO will gather operating parameters to determine what generating resources must switch off in response to temperature thresholds and establish a load forecast variable that includes known voluntary load curtailment.

He added that quantifying voluntary curtailment is “a difficult thing to do, but one that MISO will look at nevertheless.”

Grid Strategies’ Michael Goggin, representing the American Wind Energy Association, said that while there were cold-weather wind cutoffs, large amounts of imported wind from PJM into MISO helped alleviate the emergency. He also said wind generation in Michigan helped to cover Consumers Energy’s gas supply issues following a fire at a compressor station.

Goggin also said it “makes perfect sense” for MISO to keep an account of the operating cutoffs across all classes of generation.

“I think once they do that, they won’t have an issue,” Goggin said in a telephone interview with RTO Insider.

He added that significant outages across all MISO resource types on Jan. 30 were a “much larger factor” than the missed wind forecast.

“There’s just a lot of equipment failures across all resources when you have temperatures this extreme,” he said.

As with past emergencies, some LMRs did not respond or verify availability in MISO’s communication system, Arness said. The RTO will hold training for LMR owners on how to navigate its system April 23-24 and again May 21-22 in anticipation of its summer peak.

As expected, MISO’s January operations report reflected the extreme cold and emergency declaration on the last two days of the month. The RTO’s peak load of 101 GW occurred on Jan. 30.

MISO also hit a new record wind output peak of 16.3 GW on Jan. 8, besting the previous record of 15.6 GW from March 31, 2018.

MISO to Work Through 2-Hour LMR Notification

MISO plans to work with stakeholders to determine how it will provide two-hour notice to LMRs called up to respond to emergency conditions.

MISO LMR Capacity Rules Get FERC Approval.)

Customized Energy Solutions’ Ted Kuhn asked how long LMRs are on the hook under the two-hour warning should MISO need to shift the emergency declaration to a later time.

“You just need to make sure it’s clear how long they have to be available. It’s not an indefinite; it needs to be [a fixed time period],” Kuhn said.

MISO staff said it was extremely unlikely that the RTO would continuously delay an emergency declaration over several hours, but it may need a little flexibility as it monitors possible maximum generation events.

“The timing of the peak is not a fixed thing. It could come earlier; it could come later,” said Dustin Grethen, MISO market design adviser.

“The two-hour notification is just that: making sure if they have someone drive out to flip the switch, they’re driving at the right time,” MISO Director of Resource Adequacy Coordination Laura Rauch said.

The RTO will discuss the filing amendment with stakeholders during this month’s Resource Adequacy Subcommittee meeting.

— Amanda Durish Cook

March 3, 2019

NYISO Commissions New Social Cost of Carbon Study

By Michael Kuser

RENSSELAER, N.Y. — NYISO on Thursday said it has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets.

“In the last week we decided to have Analysis Group and Sue Tierney and Paul Hibbard do a fresh analysis,” Executive Vice President Rich Dewey told the Installed Capacity/Market Issues Working Group, referring to a senior adviser and principal, respectively, at the consulting firm.

“The scope of work for the Analysis Group is to build on the analysis previously done by [The] Brattle [Group] and (a) validate the findings, (b) extend the assessment based on the newly announced more aggressive policy goals and (c) identify any complementary benefits that might have been overlooked in the scope of the Brattle study,” Dewey said.

Dewey’s surprise announcement came near the end of a meeting devoted to new Tariff rules on carbon emissions and pricing. Stakeholders had begun to push ISO staffers to explain the timeline ahead of an anticipated vote on carbon pricing in the second quarter and describe exactly how the grid operator is learning whether the state supports their efforts.

“We all recognized when we started that this was new ground, uncharted territory,” Dewey said, indicating that the ISO would not present a carbon pricing package to FERC without state support. “We’re not going to take a vote and put forth a [Federal Power Act Section] 205 filing without state support. … We’re not going to ram through a vote by June without all on board.”

NYISO has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets. The above graph is from an U.S. Interagency Working Group study in 2013. | *U.S. Government Interagency Working Group on Social Cost of Greenhouse Gases*

Howard Fromer, director of market policy for PSEG Power New York, said timing is critical.

“While we are figuring out how to price carbon, the state is moving forward with significant implementation of its policies,” Fromer said. “Renewables, a host of storage solicitations and draft air emission regulations were just issued for comment that impact over 3,000 MW of peakers in the New York City-Long Island area, all affecting how the market responds and thinks about what’s happening. We can’t wait too long to decide on how to act.”

Mark Reeder, representing the Alliance for Clean Energy New York, said, “The only thing we can affect is whether or not to have a carbon price, not whether or not the state’s environmental goals are admirable.”

Filling the Gaps

A task force created in October 2017 by NYISO and the New York Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. In December, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)

“What we worked on in our stakeholder process is to get to a package that people are comfortable with, and at the end of March we’ll know what are the gaps,” Dewey said.

He added that the contract with Analysis Group is not meant to undermine the initial analysis done by Brattle, but “to look at unmonetized benefits,” whether in public health or other areas. The ISO will post details of the study as soon as possible, he said.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said he had no issues with the decision to conduct another study on the impacts of carbon pricing, but he was critical of the ISO’s decision to commission the study without even consulting stakeholders on the decision and, in particular, on the scope of the study.

Before Dewey’s announcement, Mager said, “It might be helpful to get a list of what the ISO considers to be open issues. Right now we have no clarity, and we want to understand the [carbon pricing] proposal on a comprehensive basis and go back to our clients.”

“We want more than silence from the state; we need a positive statement of support, at least when we go to FERC,” said Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers.

Rochester Energy Storage Hub | *NY-BEST*

Breidenbaugh said his clients already have uncertainties regarding subsidies, questioning how the state would structure thousands of megawatts of renewable energy contracts and whether the contracts will reflect carbon pricing effects or be layered atop them. He said they are “profoundly skeptical” about carbon pricing, especially in the context of a potential carbon tax being imposed by the state.

NYISO will discuss Tariff revisions and price calculation — specifically identifying marginal units — on March 18, and Tariff revisions again on March 28.

There will likely be at least one more meeting after that, said Nicole Bouchez, NYISO’s principal economist.

Tariff Terms, Penalties

NYISO on Thursday also prop o sed new Tariff sections to describe carbon charges, payments and residual allocation.

The ISO requires new Tariff definitions of carbon emissions and the cost of such emissions to effectuate carbon pricing, said Ethan D. Avallone, an ISO senior energy market design specialist. He also reviewed the work done so far on carbon residuals. (See NYISO Ponders Response to Carbon Charge Shortfalls.)

New sections of Rate Schedule 18 will include carbon charges and payments for import and export transactions, as well as for wheel-throughs and the carbon residual allocation, Avallone said. New sections of Rate Schedule 9 will include carbon charges for suppliers.

The Tariff language defines emissions as “point-of-production carbon dioxide emissions that result from energy injected, or start-up to inject energy, in connection with participation in the wholesale market.”

The ISO proposed a price on carbon emissions equal to the SCC — presumably as determined by the PSC — minus the value of any other state, multistate or federal charges for carbon emissions that a supplier must pay, including but not limited to emission allowance costs.

Penalties for failing to report or underreporting carbon emissions ramp up according to the severity of the lapse, from 0.5 times the applicable charge for failure to report emissions data by day 60, to 1.5 times the applicable invoice charge for failure to report by day 170, to double the charge for underreporting.

One stakeholder questioned the procedures for levying such penalties but was reassured that generators have a significant window in which to correct emissions data before being subject to penalties for underreporting or failing to report.

March 3, 2019

MISO, SPP Monitors to Conduct Seams Analysis

By Tom Kleckner

State regulators are bringing in the MISO and SPP market monitors to help solve seams issues between the two RTOs.

Potomac Economics’ Michael Wander | © *RTO Insider*

The Organization of MISO States and SPP’s Regional State Committee’s Liaison Committee has asked MISO’s Independent Market Monitor Potomac Economics and SPP’s Market Monitoring Unit to conduct a seams analysis and identify “specific seams issues from their perspective.”

Potomac’s Michael Wander and the MMU’s Keith Collins will provide a list of issues to Missouri Public Service Commissioner and OMS President Daniel Hall and Kansas Corporation Commissioner Shari Feist Albrecht, the committee’s chair and vice chair, respectively. Committee members are scheduled to hold a March 15 conference call to narrow the list for the monitors’ analysis.

“Hopefully, they will pick issues that can be monetized for ratepayers,” Hall said during a March 1 conference call.

Hall said he prefers a single report from the monitors but agreed two reports might be appropriate should their perspectives differ.

The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. That has frustrated some stakeholders and caused market inefficiencies.

Members met most recently in a closed session during the February National Association of Regulatory Utility Commissioners meeting. (See “OMS-RSC Talks Continue,” OMS Taps State Attorney for Leadership Role.)

Future meetings will be open to the public, Hall said then.

March 3, 2019

FERC: No Merit in MISO Deliverability Complaint

By Amanda Durish Cook

FERC has rejected a trade group’s complaint that MISO is improperly accounting for the deliverability of some capacity resources, saying it could find no Tariff language to support a violation.

The commission on Thursday said MISO isn’t in violation of its resource adequacy construct over capacity deliverability as the Coalition of Midwest Power Producers (COMPP) alleged late last year (EL19-28).

Rather than finding any Tariff provisions that evidenced violation, FERC said that MISO is “responsible for determining whether … capacity resources are deliverable to load.”

“Although power producers contend that ‘deliverable to load’ should be read to mean that capacity resources must have firm transmission service up to their full installed capacity levels, power producers fail to identify any Tariff provisions that support this assertion,” FERC said.

The commission also said COMPP didn’t demonstrate that MISO’s current practice jeopardizes reliability.

COMPP’s complaint alleged that MISO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The group said MISO’s megawatt count from deliverable resources comes up short annually and drives down payments to capacity resources demonstrably positioned to deliver on their obligations. COMPP asked FERC to direct MISO to develop a solution to comply with its Tariff before the 2019/20 capacity auction. (See Trade Group Lodges Complaint over MISO Capacity Rules.)

MISO’s Tariff requires capacity resources to demonstrate deliverability either by having network resource interconnection service (NRIS), which stipulates that the entire ICAP of the resources must be deliverable, or by having energy resource interconnection service (ERIS) and procuring firm transmission service up its UCAP level.

No Discriminatory Treatment

In response to the complaint, MISO said it doesn’t hold capacity resources to different standards because it doesn’t require NRIS resources to perform to ICAP levels, instead requiring both to demonstrate deliverability up to their UCAP levels for the purposes of the capacity auction.

FERC agreed. “As described in its resource adequacy Business Practices Manual, MISO calculates the [UCAP] level of a resource by first determining its [ICAP] level. Once the [ICAP] value is determined, MISO applies the resource’s forced outage rate, thereby converting the [ICAP] level to a lower [UCAP] level. Next, MISO validates that the resource is deliverable by having the resource demonstrate deliverability up to its [UCAP] level,” FERC said.

The commission also said UCAP values are a vital part of MISO’s resource adequacy construct, with even the reserve margin formed as an “unforced capacity requirement.”

“Given the consistent use of unforced capacity values for purposes of resource adequacy in … its Tariff, we find that MISO reasonably implemented [its Tariff] by requiring capacity resources with ERIS to demonstrate deliverability up to their unforced capacity levels,” FERC said.

MISO said COMPP mischaracterized its Tariff “process improvements” discussions with the Independent Market Monitor as “admissions of Tariff violations.” The RTO has promised to have stakeholder discussions about resource deliverability and LOLE implications, with any potential fixes aimed at the 2020/21 capacity auction. (See “Capacity Auction Recommendations,” MISO Concurs with Monitor Ideas, Pledges More Study.) It said there was no evidence it violated Tariff provisions establishing a planning margin, the LOLE study methodology to create the planning margin or its duty to ensure the deliverability of capacity resources. MISO also said working on a rule change less than a month before the April capacity auction would seriously disrupt the auction.

At any rate, transmission deliverability is outside the scope of its LOLE analysis because the study assumes no internal transmission constraints, the RTO added.

However, the Monitor had asked FERC to side with COMPP, agreeing that “the terms of the Tariff result in a mismatch for some ERIS resources between the capacity assumed to be available in the LOLE studies and the capacity those suppliers can actually deliver.” But the Organization of MISO States urged FERC to hold off on ordering relief so the RTO could continue to address the issue through ongoing stakeholder discussions.

‘False Sense of Urgency’

MISO said the complaint created a “false sense of urgency” by implying that its recent emergency events had anything to do with capacity deliverability. To the contrary, the RTO said the events “have been driven largely by correlated planned outages and the use of emergency-only resources outside of the summer season.”

The RTO also argued that the power producers represented by COMPP are not prevented from auction participation nor are they suffering harm from MISO’s existing rules. It also said COMPP should have first sought dispute resolution with MISO. Finally, MISO alleged the complaint only sought to “disqualify 1,400 MW of generation owned by other auction participants to gain a competitive advantage.” The Monitor last year said as much as 1,400 MW worth of capacity resources needed to meet reserve requirements may not have been deliverable in the 2018/19 planning year.

March 3, 2019

FERC: Stability Deviation Method Best for Artificial Island

By Christen Smith

PJM’s “stability deviation” method best suits cost allocation for the Artificial Island project, FERC said Thursday, denying rehearing requests from transmission owners who favor the status quo.

The ruling comes eight months after the commission established a paper hearing to settle on the calculation for determining how PJM should distribute costs for grid stability projects, agreeing — in this case and for future stability upgrades — the existing solution-based distribution factor (DFAX) method doesn’t align allocations with benefits (E L 15-95).

“Based on the record developed through the additional hearing procedures, we find that the stability deviation method is a just and reasonable replacement rate for PJM to apply to all of the costs of lower-voltage facilities that address stability-related reliability issues and [to] 50% of the costs of regional facilities and necessary lower-voltage facilities that address stability-related reliability issues, including the Artificial Island project,” FERC concluded in its Feb. 28 ruling.

The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | *BHI Energy*

Unjust and Unreasonable Status Quo

The debate stems from a yearslong discussion over who should pay for new transmission lines between New Jersey and Delaware to address stability limits on generation at the Salem and Hope Creek nuclear plants and transmission constraints that sometimes prevent the generators from exporting power at full capacity. Such a project is rare and doesn’t conform well to the DFAX method, PJM contends. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?)

For reliability projects, PJM assigns 50% of the costs of regional facilities (500-kV lines or higher and double 345-kV lines) and “necessary” lower-voltage facilities required to support regional lines on a load-ratio share basis. The other 50% is allocated using DFAX. All costs of lower-voltage facilities not supporting regional lines are allocated via DFAX.

Using this methodology, 93% of the $280 million Artificial Island project cost would have fallen on Delmarva Power & Light — much to the dismay of Maryland and Delaware utility regulators who said the distribution disproportionately targeted their ratepayers.

In July, FERC agreed with the state commissions, noting that unlike thermal overloads, the parties that cause stability issues don’t necessarily have flows on the corresponding transmission facility. While Delmarva customers will use the new transmission lines from the Artificial Island project, the company neither caused the need for the lines nor does it benefit from those flows sufficiently because its transmission system already was adequate to serve its load, FERC found.

“While Delaware load will receive some increase in reliability from having a more robust transmission system, we find that the costs that would be allocated to the Delmarva parties under the solution-based DFAX method would not be at least roughly commensurate with the benefits received,” FERC concluded.

Stability Deviation Method

PJM long agreed it needed a different way of divvying costs for stability-related issues, noting those who cause these problems aren’t always the same ones who will benefit from it being repaired — such as in the cases of thermal violations, voltage/reactive issues, storm hardening, end-of-life/aging infrastructure or real-time operation concerns.

Staff crafted a few different possibilities, including the stability deviation method, which determines that a measurement of the change in the voltage angle is higher for substations that are more impacted by a disturbance or stability event, also referred to as the angular deviation. This change would identify the loads that would be most impacted by a stability disturbance and would benefit from transmission projects that address stability-related issues.

Under this calculation, costs of the Artificial Island project would fall 19% to the Public Service Electric and Gas, 15% to PECO Energy, 12.5% to PPL, 12.4% to Jersey Central Power & Light, 10.4% to Delmarva Power, 7.2% to Atlantic City Electric and about 5% to Metropolitan Edison. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

TOs described the method as arbitrary, unexplained and unjustified, saying it amounts to the opposite of the basic underlying principle of PJM transmission cost allocation in the post-Order 1000 era. Instead, TOs pushed for a reversion back to the status quo — an idea FERC outright rejected.

“The PJM transmission owners have not demonstrated that, for transmission facilities addressing stability-related reliability issues, it would be just and reasonable to revert to the solution-based DFAX method to identify the beneficiaries of transmission facilities, once the stability-related reliability issue supporting the need for the transmission facility is resolved,” the commission said. “Further, while the PJM transmission owners’ reversion proposal identifies retirement of generating facilities as triggering the reversion, other system topology changes, such as transmission facility enhancements or expansion, may also affect the stability concern, but are not addressed by the reversion proposal.”

March 1, 2019

NYISO Management Committee Briefs: Feb. 27, 2019

RENSSELAER, N.Y. — NYISO stakeholders on Wednesday concluded an unusually lengthy public policy transmission planning process and reviewed a revised report and new analysis for selection of two AC transmission projects to improve transfer capability into the New York City area.

The new analysis by ISO staff followed a December decision by the Board of Directors to decline the Management Committee’s recommendation to build Project T029 — a standard 345-kV line from Knickerbocker to Pleasant Valley — on Segment B, a section of the grid feeding the Upstate New York/Southeast New York (UPNY/SENY) electrical interface. (See NYISO Board Partially Reverses AC Tx Project Selection.)

ISO staff are now recommending Project T019, as is the board, saying it has the highest incremental UPNY/SENY transfer capability, which results in the lowest cost-per-megawatt ratio, highest production cost savings, greatest CO2 emissions savings and highest Installed Capacity (ICAP) savings of the Segment B projects, Zach Smith, vice president for system and resource planning, told the committee.

The board did not object to the committee’s selection of Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A, which feeds the Central East interface.

Advised by consultant Substation Engineering Co., NYISO reviewed seven proposals for Segment A and six for Segment B before making their choices last June. (See NYISO MC Supports AC Transmission Projects.)

Project T019 was proposed by National Grid’s Niagara Mohawk Power and NY Transco, while North America Transmission (NAT) and the New York Power Authority together proposed both projects T027 and T029.

Cost estimates for both NAT/NYPA projects ranged from $900 million to $1.1 billion. The estimated capital costs for T027 and T019 are higher, at $1.2 billion, but the project is made more cost-effective by the up to 550 MW of additional N-1 emergency transfer capability provided on UPNY/SENY by T019, Smith said.

The ISO estimates the two AC transmission projects, if approved by the board in March, will be in service by December 2023.

Process Matters

NYISO Public Policy Tx Revisions Approved.)

Lawrence Willick of LS Power said the incremental benefits of T019 do not justify the incremental costs, but New York Transco General Counsel Kathleen Carrigan said the ISO on two occasions (including with the selection of T027 for Segment A in the AC Transmission PPTN and for the Western New York PPTN) has recommended projects with higher capital costs to be selected as the most efficient or cost-effective solution to satisfy a PPTN. In both cases, she said, the higher capital costs correlated to significantly greater benefits to the statewide electric system than the lower-cost alternative proposals. She contended that the ISO should take a similar approach in its recommendation for Segment B as well.

Several stakeholders requested an opportunity to address the board, and LS Power and NY Transco will make oral presentations on March 18, one day before the board meets, interim NYISO CEO Rob Fernandez said.

“We only wish to present if LS Power presents — if they don’t, we don’t,” Carrigan said. Fernandez responded that the ISO would work out the details soon. Comments on the PPTN review were due Friday.

The ISO estimates the two AC transmission projects, if approved by the board in March, to be in service by December 2023. | *NYISO*

Stakeholders in January informed the ISO of a modeling error in the analyses, specifically that the impedance data had been transposed for the New Scotland-Knickerbocker and Knickerbocker-Alps 345-kV projects.

“We corrected the impedance and confirmed it with the developers,” Smith said. “The ISO also revised its dispatch methodology after the board said it created a perception of a constraint. The board requested we dive a little deeper into operability analysis.”

Specifically, the impedance data correction impacted the UPNY/SENY limit, he said. For T019, the incremental UPNY‐SENY emergency transfer capability decreased from the previously calculated level of 2,100 MW to 1,850 MW. For T029, the data correction caused the incremental emergency transfer capability to increase from 1,150 MW to 1,300 MW.

Additional analysis also included a “sensitivity” in which the G‐J Locality is eliminated and a new H‐J Locality is created.

“The capacity scenario should be eliminated as being more misleading than useful,” said Mark Younger of Hudson Energy Economics, which helped the Independent Power Producers of New York submit comments on the analysis. IPPNY took no position on the board’s PPTN project selection.

Younger said it was unreasonable to assume capacity could be replaced in the more densely populated areas of Zones H and I for the same price as in the more rural Zone G, and that it was also impossible that the market would not respond to stopping payments to resources based on their locational value. He also noted that NYISO’s own analysis in the study showed that there continues to be a need for capacity in Zone G.

Entry and Exit Modeling

“One of the things that limits the benefits from the recommended projects is limited transfer capability south of the projects, so future increases in transfer capability south of these projects could lead to substantial additional benefits,” said Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit.

“At the same time, if the PSC relies more on offshore wind than upstate renewables to achieve the goals of the Clean Energy Standard, then it would tend to reduce the benefits,” so the location and amount of intermittent renewables is in flux, he said in summarizing his report’s conclusions.

NYISO’s public policy transmission planning process calls for the Monitor to review and consider the impacts on the ISO’s markets.

The Monitor made several recommendations for improvement, but LeeVanSchaick particularly highlighted one: to model entry and exit decisions for generators in a manner consistent with the expected competitive market outcomes.

“If the ISO could incorporate entry and exit scenarios into its modeling, that would be very useful for ensuring the scenarios provide a realistic picture of the future benefits of the projects,” he said.

Marc Montalvo of Daymark Energy Advisors, representing the New York Department of State’s Utility Intervention Unit, said the UIU was concerned, as were several other stakeholders, about the qualitative measures being applied and decisions being reached in a different way from the MC’s understanding during its serious deliberations.

“We ought to make sure we are not creating a process that gives developers pause,” Montalvo said. “Given how much time and energy on behalf of the developers goes into the process, the last thing we want to see is a lack of confidence … whereby developers might choose not to participate, reducing the efficiency of market outcomes and possibly harming consumers.”

— Michael Kuser

March 1, 2019

NEPOOL Seeks Rehearing on Press Ban Order

By Rich Heidorn Jr.

The New England Power Pool indicated Thursday it won’t let reporters into its meetings without a fight, asking FERC to reconsider its order rejecting the group’s press ban.

The commission ruled unanimously Jan. 29 that it had jurisdiction over NEPOOL’s membership rules and that barring journalists from joining was unduly discriminatory (ER18-2208-001). (See FERC Rejects NEPOOL Press Membership Ban.)

NEPOOL Participants Committee | *NEPOOL*

FERC said it would rule separately on RTO Insider’s complaint under Section 206 of the Federal Power Act asking the commission to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

The stakeholder group sought to amend the NEPOOL Agreement to bar members of the press from membership after RTO Insider reporter Michael Kuser, an electric ratepayer in Vermont, applied to join as an End User in March 2018.

In its request for rehearing or clarification, NEPOOL contended that “the commission’s jurisdictional determination not only lacks sufficient explanation, but its conclusion that the membership provisions are jurisdictional is potentially limitless in scope.

“Under these circumstances and given the issues pending before the commission in the complaint proceeding in Docket No. EL18-196, NEPOOL files this request to preserve its rights until the commission provides clarity and explanation for its decision to exercise jurisdiction over the membership arrangements of an entity that does not provide wholesale power or transmission service to any customer,” the organization continued.

The commission’s order rejected NEPOOL’s contention that its membership provisions were not FERC-jurisdictional, concluding that “they directly affect commission-jurisdictional rates.”

NEPOOL said FERC’s ruling cited as precedent only “one factually dissimilar case … and provides no explanation as to how the cited precedent supports the commission’s jurisdictional claims.”

The case cited was a 2016 ruling involving PJM in which the commission found that the RTO stakeholder process is “a practice that affects the setting of rates, terms and conditions of jurisdictional services.” The commission made the filing in rejecting rehearing of an order approving PJM’s funding of the Consumer Advocates of the PJM States. (See FERC Upholds PJM Advocates’ Funding.)

“Without an explanation of how and why PJM is relevant to the treatment of NEPOOL’s membership amendments, the January order fails to meet the commission’s obligation to carry out reasoned decision-making,” NEPOOL said. “NEPOOL requests that the commission further articulate the basis for its conclusion that the membership amendments are jurisdictional. As it stands, the January order could be read to sweep virtually any NEPOOL practice, procedure or protocol under commission jurisdiction, no matter how tangential to rates, terms or conditions of jurisdictional service.”

NEPOOL said the commission’s reasoning was “similar to the expansive view of its jurisdiction that was rejected” by the D.C. Circuit Court of Appeals in its 2004 CAISO ruling.

In that case, the court rejected FERC’s attempt to replace CAISO’s Board of Governors, ruling that the commission “does not have the authority to reform and regulate the governing body of a public utility under the theory that corporate governance constitutes a ‘practice’ for ratemaking authority purposes.”

Membership Pending

NEPOOL’s rehearing request comes two weeks after its Membership Committee recommended to the Participants Committee that Kuser be granted membership. The Participants Committee has listed the issue on the agenda for its next meeting, March 13.

In addition to seeking to change its Agreement to bar press from membership, NEPOOL last year also amended the Participants Committee bylaws to limit the ability of meeting participants to share what they’ve heard.

The new language — which was not submitted for FERC approval — states that: “Attendees may use the information received in discussion, and may share the information received within their respective organizations or with those they represent, provided those who receive such communications are not press and also are aware of and agree to respect the nonpublic nature of the information. In no event may attendees reveal publicly the identity or the affiliation (other than sector affiliation) of those participating in meeting discussions.”

The commission’s January order left that prohibition intact.

March 1, 2019

MISO MEP Cost Allocation Plan Goes to FERC

By Amanda Durish Cook

MISO and a majority of its transmission owners on Monday filed a new cost allocation plan with FERC that would change the way the RTO allocates costs for its market efficiency projects (MEPs).

The proposal applies to MISO’s 2019 Transmission Expansion Plan and includes MISO South, which saw its five-year transmission cost-sharing moratorium expire at the end of 2018.

The 622-page filing includes proposals to lower the voltage threshold for MEPs from 345 kV to 230 kV and eliminate a 20% footprint-wide postage-stamp cost allocation method for projects. It will also create two new project benefit metrics: the value of deferred or avoided reliability transmission projects, and the value of reducing power flows on the contract path on shared transmission from MISO Midwest to South (ER19-1124 , ER19-1125).

The proposal additionally creates a new category for economic projects below 230 kV and above 100 kV where 100% of costs would be allocated to the local transmission pricing zone. Such projects were previously categorized as “other” transmission projects without clear allocation rules.

MISO said the proposal was “extensively vetted” through its stakeholder process for more than three years. It noted that the package creates “additional opportunities for the identification and approval of market efficiency projects and greater precision in cost allocation for such projects, and formalizes the process for development of locally based economically beneficial projects.”

The RTO told FERC that the lower voltage threshold will likely result in more MEPs and, by extension, more opportunities to bid projects under the competitive transmission process. Because of the expected uptick in activity, MISO also proposed a limited exception to the competitive selection process for MEPs that can also demonstrate an immediate reliability need. The exception would only apply when a lengthy bid selection process would push a project’s in-service date past the expected reliability need date, MISO said, urging the commission to accept the provision, because it had approved similar selection exceptions in three other RTOs.

More Benefit Metrics?

MISO last year opened the door to the two new benefit metrics on MEPs besides the usual adjusted production costs; earlier this month staff signaled willingness to add even more benefit metrics to the list this year.

At the February Planning Subcommittee meeting, MISO planning coordinator Adam Solomon said the RTO and stakeholders will likely begin with ideas that didn’t make the cut last year, including increased capacity import and export limits, reduced congestion from fewer transmission outages, reduced transmission losses and the ability of a project to boost grid resilience.

MISO will work with stakeholders to identify new benefit metrics to pursue during the first half of the year and then determine how to quantify them during the second half. The work could culminate in a FERC filing by the end of the 2019.