NEPOOL Debates Parameters for 2025/26

The NEPOOL Markets Committee last week debated 13 amendments to proposed updates to parameters for Forward Capacity Auction 16 (2025/26).

Many of the amendments, which were discussed during the last half of the committee’s Oct. 6-8 virtual meeting, challenged revenue figures proposed by Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE to update the FCM parameters.

Deborah Cooke, the RTO’s principal analyst for market development, prese n ted responses to stakeholder questions about updates to the net cost of new entry (CONE) and offer review trigger prices (ORTPs).

The discussions continued a debate from the committee’s September meeting and previewed votes scheduled for November. (See ISO-NE Challenged on Win d , Solar, Storage Revenues.)

Face-off on Offshore Wind

Abby Krich and Alex Worsley of Boreas Renewables presented four amendments on behalf of RENEW Northeast, includi n g capital costs and the investment tax credit for the ORTP calculation for offshore wind. A capacity offer below the ORTP triggers a unit-specific review by the Internal Market Monitor to verify the resource’s cost.

RENEW said the RTO’s proposal to use $5,876/kW (2019$) for the overnight capital cost of OSW and assumption of a 0% tax credit results in an ORTP of $52.46-$52.67/kW-month, which RENEW believes is double the actual cost. [Editor’s note: An earlier version of this article did not include ISO-NE’s updated figures.] RENEW has proposed using a lower overnight capital cost of $3,000/kW (2019$) and a higher tax credit of 18%.

Krich said $3,000/kW is a reasonable, middle-of-the-range estimate of expected costs for OSW projects in New England. A capital cost of up to $3,200/kW would still result in an ORTP of $0.

CEA sai d the RENEW analysis is “inappropriate,” and its estimated ranges should be revised upward. CEA challenged RENEW’s use of data from European and Chinese projects.

Krich told RTO Insider after the meeting that ISO-NE’s cost was accurate “8-10 years ago,” but they are no longer appropriate.

‘More Reasonable’ EAS Revenues

Ben Griffiths, an energy analyst for the Massachusetts Attorney General’s Office, offered a summary m emo and present a tion that outlined “a straightforward optimization model to more reasonably estimate” energy and ancillary services (EAS) revenue available to a storage device. Griffiths said the AG’s model produces “an operational schedule for storage that maximizes revenues” from participation in three of the RTO’s markets — energy, 10-minute spinning reserves and regulation — while respecting the storage device’s technical limitations.

The Block Island Wind Farm, off Rhode Island | *Block Island Ferry*

Griffiths added that the AG disagrees about the “reasonableness of the CEA EAS revenue estimates for battery storage resources.”

A reasonable operator using a battery for energy, reserves and regulation should be able to earn $54.87/kW-year, assuming the Forward Reserve Market (FRM) sunsets, and $59.11/kW-year, assuming the FRM is maintained, Griffiths wrote. CEA’s contrasting estimates average EAS revenue from these three markets at $45.71/kW-year with an FRM sunset and $55.26/kW-year assuming it is maintained.” (See “Support for Forward Reserve Market Sunset,” N E POOL Markets Committee Briefs: Oct. 6-8, 2020.)

Griffiths said these revenue estimates are “conservative” and the AG’s office “fully expects that more advanced dispatch schemes could yield higher revenues.”

NEPGA Proposes Amendments on Amortization Period, Owner’s Cost

The New England Power Generators Association (NEPGA) pro p osed changing the amortization period for the net CONE reference unit (a GE 7HA.02 gas-fired combustion turbine) to 15 years from 20 years. NEPGA’s Bruce Anderson said the 20-year amortization period fails to reflect the risks faced by developers, which creates “a finite period concluding in economic obsolescence.” There is “no evidence that the reference unit would be able to sustain its annual cash flows in real dollar terms for 20 years,” he added.

Anderson said NYISO recently reduced its reference unit’s economic life to 17 years to recognize the potential impact of New York state law and policy. In New England, most states have renewable portfolio standards requirements that involve the procurement of energy from non-carbon-emitting resources.

Additionally, NEPGA put forth an amend m ent that would take a “bottom’s up approach” to the owner’s cost. NEPGA proposes $12.45 million in owner’s cost — almost five times Mott McDonald’s $2.5 million estimate, which Anderson said is “woefully inadequate” to cover the known owner’s costs, let alone any contingencies.

NEPGA said its figure takes into account initial screening studies and work sufficient to qualify for the FCA and obtain a capacity supply obligation (CSO), plus activities necessary to install the equipment, interconnect it and ensure successful commercial operation. NEPGA said it ignored costs associated with electrical interconnection, network upgrades, gas interconnection, gas pipeline upgrades, initial fuel inventory and financing costs, while Mott McDonald said its estimate captured these activities and contingencies.

At NEPGA’s request, CEA and Mott McDonald upda t ed their dispatch to include seasonal intraday fuel price premiums ranging from 4% in summer to 20% in winter.

NEPGA had asked for time on the agenda to amend the net CONE proposal to include an intraday premium in the event CEA and Mott McDonald chose not to account for it in their updated modeling. NEPGA said it will evaluate the consultants’ proposed intraday premium accounting and could bring forward an amendment at the November committee meeting.

NESCOE Amendments Look at Reference Unit, PfP

While NEPGA sought to shorten the reference unit’s assumed life, NESCOE said it should be increased. NESCOE’s t w o amendments would boost the useful economic life of the reference unit to 25 years and escalate pay-for-performance (PfP) revenues to account for inflation.

NESCOE proposed that the net CONE resource should be increased to reflect the expected economic life of the reference unit and that PfP should be increased for inflation, reflecting the recalculation of the performance payment rate (PPR) every three years. There are no corresponding Tariff language revisions since these amendments are changes to input assumptions in the analysis.

Calculating net CONE using a 25-year life for the resource reflects a better balance between the physical life of these facilities and a reasonable expectation of their economic life, NESCOE said. The estimated reduction in net CONE is $0.63/kW-mo. Adjusting PPR revenues for inflation is more consistent with the treatment of other revenues with an estimated reduction in net CONE of $0.12/kW-mo., it added.

October 12, 2020

PJM MIC Briefs: Oct. 7, 2020

PJM stakeholders last week endorsed a “quick-fix” manual revision to correct a date reference in Manual 18 following a discussion in which some members objected to the process and suggested further talks on lingering pseudo-tie issues.

Jeff Bastian of PJM reviewed the problem statement and issue charge to correct Manual 18’s reference to the effective date for notifying pseudo-tied resource owners of their assigned locational deliverability area (LDA) prior to each delivery year. The Market Implementation Committee endorsed the measure with 78% support (149 votes) at its Oct. 7 meeting.

Bastian said under initial Capacity Performance provisions, a performance shortfall was calculated for external generation capacity resources only during performance assessment hours for when the emergency action was declared for the entire PJM region.

However, in November 2017, FE R C accepted changes to be effective with the 2020/21 delivery year that would calculate a performance shortfall for external generation capacity resources for any performance assessment interval for which performance by such external resources would have helped resolve the emergency (ER1 7 -1138). (See FER C OKs Change to MISO, PJM Pseudo-Tie Rules.)

PJM Manual 18 changes made to conform with the accepted provisions incorrectly specified the provisions as being effective with the 2021/22 delivery year, Bastian said.

Carl Johnson of the PJM Public Power Coalition said he recognizes what PJM was trying to accomplish with the change and why it would be done in the quick-fix process. Johnson said he represents some members who were involved in the FERC docket on the issue who still have concerns they feel are unresolved and would like to see PJM address them in a new problem statement and issue charge.

Johnson said the PPC would like to address some of the issues that FERC said were out of scope for the proceeding but should be raised in the stakeholder process. He cited questions about pseudo-tied resources’ obligations, how they receive pricing and penalties that may be imposed on an external resource. (See FERC Sets Hearings in PJM H y dro Pseudo-Tie Spat.)

Carl Johnson, PJM Public Power Coalition | © *RTO Insider*

Steve Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power (AMP), said he agreed with Johnson about opening a stakeholder process to examine unresolved issues. AMP was one of the entities that challenged PJM’s requirements for pseudo-tied generators. (See FERC Si d es With PJM on Pseudo-Tie Challenges.)

Lieberman said he was concerned by PJM’s use of the quick-fix process to make the change because it affects a specified delivery year that has already started.

“It just strikes me as a little unsettling that we would be making a change after the start of a delivery year,” Lieberman said. “I just don’t like seeing us go down the path of making changes that specify a specific start time that’s already passed.”

Bastian said the Tariff correctly lists the 2020/21 delivery year as the effective date, superseding the manual language. Bastian said the idea was to make the two documents consistent and eliminate the discrepancy.

Sharon Midgley of Exelon said her company is supportive of PJM’s quick-fix and didn’t think it was appropriate to hold up a conforming change to a manual to discuss other issues. Midgley said Exelon would support stakeholders continuing a discussion and bringing forward a new problem statement and issue charge.

Behind-the-meter Generation

Members unanimously endorsed clarifications to the behind-the-meter generation (BTMG) business rules for units changing status from netting against load to participating in PJM markets.

Terri Esterly of PJM review e d the problem sta t ement and issue cha r ge addressing the clarifications, saying a BTMG unit can be designated as a capacity resource or energy resource in the wholesale markets or be designated as BTMG netting against load on a unit-specific or partial-unit basis. Any BTMG unit seeking to be designated in whole or in part as a wholesale resource must submit an interconnection request.

BTMG rules were developed beginning in 2003 within the Behind-the-Meter Generation Working Group, Esterly said, and there has been limited review of the rules governing them since their development. Esterly said the OC in 2019 endorsed clarifying updates to BTMG business rules focused solely on the reporting, netting and operational requirements of non-retail BTMG.

Esterly said the Tariff and Manual 14D updates are needed because of the increased development of distributed energy resources and load-serving entity requests for adjustments to network service peak load and obligation peak load to reflect new BTMG.

PJM — Sharon Midgley, Exelon | © *RTO Insider*

The key work activities include providing education on existing BTMG business rules on status changes in the Tariff and Manual 14D. Work also will include reviewing and identifying business rules related to status changes that would benefit from clarification or additional detail or that may conflict with existing rules.

Stakeholders are expected to work on the issue for four months.

Midgley asked how the BTMG effort lines up with PJM’s compliance activities associated with FERC Order 2222 and what steps the RTO will take to make sure there are no conflicts between what stakeholders develop in the BTMG effort versus what is developed for Order 2222. (See FERC Opens R T O Markets to DER Aggregation.)

Esterly said the BTMG effort is to clarify existing rules but additional changes may be needed because of Order 2222.

Real-time Values Market Rules

Laura Walter, senior lead economist, provided an upd a te on the work completed during the MIC special sessions on real-time values market rules and reviewed the proposed packages from the solutions ma t rix.

The special sessions have been taking place since January, after stakeholders endorsed an issue charge at the December Markets and Reliability Committee meeting. (See “Real-time Values,” PJM MRC Brief s : Dec. 19, 2019.) The problem state m ent said observations indicated real-time values were being used to consistently override unit-specific parameter limits or approved parameter limited exceptions.

The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources couldn’t meet their unit-specific parameter limits or approved exceptions, Walter said. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.

In a nonbinding poll conducted in August, 55% of stakeholders said they supported the PJM package, and 10% gave support for the IMM package, while 71% said they were happy with the status quo.

Walter said market participants that repeatedly fail to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. The package also calls for adding real-time values to the Tariff. Currently, real-time values are mentioned only in the manual, Walter said.

The IMM proposal includes removing minimum run time from the list of eligible parameters with RTV submissions. It also said units that choose to run longer can self-schedule beyond the minimum run time, with PJM operator notification.

The proposal also prevents withholding by using longer minimum run time, Walter said. Any penalties collected are to be allocated to daily real-time load.

The MIC will vote on the PJM and IMM packages at the November meeting with a first read scheduled for the December MRC meeting.

Manual 15 Review

Stakeholders unanimously endorsed revisions to Manual 15 as part of the biennial review. Gabrielle Genuario of PJM reviewed upda t es to Man u al 15, including reformatting and rewording in sections 2.6.1 and 2.6.8 to provide more clarity.

The revisions will be voted on at the Oct. 29 MRC meeting and the Nov. 19 MC meeting.

Manual 11 Revisions

Vijay Shah of PJM revi e wed proposed updates to Manual 11: E n ergy & Ancillary Services Market Operations. Shah said the changes involve increasing transparency and conforming to current PJM process as part of the five –minute dispatch and pricing problem statem e nt.

The changes include an added reference to the day-ahead and real-time sections in Section 2.2: Definition of Locational Marginal Price and updated “LMP verification” to “price verification” throughout Section 2.10: Verification Procedure as verification includes review of real-time and ancillary service prices.

Stakeholders will vote on the proposed updates at the November MIC meeting.

October 12, 2020

OSW Growth to Test New York’s Transmission Grid

Transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected without coordinated planning, NYI S O told state officials Friday.

The state hopes to develop 9,000 MW of offshore wind (OSW) by 2035.

Having offshore wind energy interconnect to load centers in the city and on Long Island “certainly helps offset some of the transmission constraints that you might experience; but nevertheless, to meet a total 9,000-MW goal of offshore wind, there absolutely will be transmission constraints,” said NYISO Vice President for System and Resource Planning Zach Smith at a technical conference hosted by the state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA).

New York offshore wind — This NYISO map shows renewable generation that would be curtailed because of insufficient bulk and local transmission capability to deliver the power. | *NYISO*

The conference was intended to inform a study to be completed by year-end on an investment plan to be established by the Public Service Commission for distribution and local transmission upgrades and a second plan for bulk system transmission investments (Case No. 20-E-0 1 97). (See NYPSC Launches Grid Study, Extends Solar Funding.)

Offshore wind is central to compliance with the Climate Leadership and Community Protection Act (CLCPA, A8 4 29), which mandates that 70% of electric power in New York come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040.

Smith noted that in the 2019 Congestion Assessment and Resource Integration Study (CARIS), published in July, the ISO only modeled 6,000 MW of OSW for the 70%-by-2030 scenario. As generation increases up to 9,000 MW, transmission constraints around the city and Long Island will worsen, he said. (See Bulk T x, 115-kV Upgrades Needed for NY 70×30 Goal.)

“There could even be a tipping point, where as you increase beyond that 6,000 MW, it could get much worse than what we’ve identified,” Smith said. “We assumed projects be interconnected according to what’s been proposed in the NYISO interconnection queue. [It’s possible] projects might interconnect much differently than what we assumed in our study, and if they do, then the results will change.

“We believe in general that our results are valid in terms of being indicative of constraints, but when you really dive into the details … those individual transmission constraints really are driven by some of the assumptions on points of interconnection, and that is particularly true with regard to offshore wind,” he said.

HVDC Gains Favor

Technology providers and independent transmission developers also presented the conference with their ideas on how New York’s grid could evolve, including the prospect of more high-voltage direct current (HVDC).

Ben Marshall of the National HVDC Cen t re in Scotland said the capacity of HVDC in Great Britain will grow from 8 GW today to an estimated 45 GW by 2028 and is expanding in other parts of Europe as well, especially in conjunction with offshore wind interconnections.

Electronic devices that measure the system and take actions increasingly dictate the performance of the grid, Marshall said. Decisions around constraints operate across seconds, decisions around frequency operate across second- to half-second periods and decisions around voltage control are made across hundreds of milliseconds, Marshall said.

“Control systems are making decisions within tens of microseconds; they’re operating very quickly, very flexibly, and it’s important that they operate correctly,” he said.

Marshall also pointed to the emerging risks of having system controls be digital rather than analog: “If I look under the hood of an older car, I know what I’m seeing with the carburetor, but in a new one, all I see is plastic … which is similar to what’s going on with the proprietary control systems, so you need either to counter that effect or to contain it.”

Elizabeth Griffin of Con Edison Transmission said DC technology will be a critical tool to maximize the state’s transmission investments.

“Based on currently proposed projects, it appears that DC will be the future for projects to bring renewables downstate via a potential Tier IV REC [renewable energy credit] procurement, as well for the upcoming offshore wind procurements, just given the distance of the current leaseholds from potential interconnection points,” Griffin said.

DC also has several advantages over AC that make it particularly well-suited for New York’s emerging transmission needs. “DC allows for the maximum utilization of transmission capacity – in the same right of way you can flow more power over DC – as well as for a level of control that is not available on AC lines,” she said. “DC also allows for long distance underground and underwater transmission options that we think will help improve community acceptance by avoiding the need to install additional transmission towers.”

Regulators need to determine how to manage transmission, and particularly how NYISO will operate intrastate DC lines that are integrated with the existing New York Control Area network to maximize its advantages, Griffin said.

Shared infrastructure can maximize the benefits and minimize the environmental impacts of transmission, “which can be particularly beneficial for offshore wind and for aggregating renewables to bring them into New York City,” Griffin said. “Unfortunately, the substations themselves, particularly in Zone J, are often very constrained due to limited real estate, limited physical space within the substation and limited electric capacity. When an open bay at a substation is used to connect less than the maximum capacity potential for that substation, the ability to connect additional volumes without physically expanding the substation may be lost.”

Creating access to the existing transmission grid will require significant additional underground transmission infrastructure that would be best developed with expansion in mind and shared among transmission projects, she said.

“Well-planned and coordinated transmission can make sure that these limited interconnection points are used to provide the maximum benefit and capacity to the system,” Griffin said. “A separate offshore grid will be better for customers in terms of grid reliability, flexibility and total cost effectiveness when compared to the individual generator lead-line approach that has been pursued to date and was appropriate for the initial projects.”

Pancaking and Cost Savings

Transmission developer Anbaric Development Partners determined that 1,500 MW of load was typical of 3 a.m. on any Sunday on Long Island and that therefore there will always be more wind than load. So early on, it started to think about where to put this energy.

The company found 23 points of interconnection (POI) in the city and on Long Island, which screening reduced to about a dozen. Some of the POIs were in good locations but needed to be upgraded to increase their injection capability, said Anbaric Partner and Project Manager Howard Kosel.

“We set a criterion of $1 million per megawatt, and we capped it at $50 million, because we had to set the bar somewhere,” Kosel said. “As we started to grow to get to the 9,000 MW, we were [learning about] the impact the particular POI had on the next POI … it became obvious that upgrading POIs required careful sequencing so as to prevent pancaking, whereby the next POI loses transfer capacity … [and] we saw that we could save upgrade costs of $500 million to $1.2 billion.”

Offshore wind’s intermittency will be complemented by solar and wind energy from northern, central and western New York state, where three public policy transmission projects are now underway under FERC Order 1000.

Innovation is a key benefit for those projects, said Lawrence Willick, senior vice president for project development at LS Power Development, which is partnering with the New York Power Authority on a 345-kV transmission project to relieve congestion at the Central East interface.

“In each case, the selected proposal was selected because of the unique technical features,” Willick said. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

Fernando Gallinas Victoriano, business development manager for Avangrid Networks, said that integrating 9 GW of offshore wind requires “a planned, coordinated approach” for New York City and Long Island.

“The HVDC technology could be used over existing cables and rights of way, or even through new greenfields, in order to facilitate larger transfer capacity in the system, and with lower implementation periods,” Victoriano said. “Incremental transfer capacity with neighboring systems will bring significant reliability benefits to New York.”

Paul Haering, vice president of capital investments at NY Transco, said that technology and innovation will be critical to achieving the state’s clean energy goals, and that the long time it takes to build transmission “is why we need to act quickly.”

NY Transco was created to develop and own high-voltage electric transmission facilities in New York, and comprises the transmission subsidiaries of Avangrid, Con Edison, National Grid and Central Hudson Electric and Gas.

October 12, 2020

PJM PC/TEAC Briefs: Oct. 6, 2020

Installed Reserve Margin Study Results

PJM stakeholders last week unanimously endorsed an installed reserve margin (IRM) of 14.4%, down from 14.8% required in 2019, along with new winter weekly reserve targets.

During the Oct. 6 Planning Committee meeting, PJM’s Patricio Rocha Garrido reviewed the 2020 R eserve R equirement S tudy (RRS) results, which determined the IRM and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establishes the initial IRM and FPR for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties (CBOT).

The 2020 capacity model is putting downward pressure on the IRM, Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.78%, compared to 6.03% in the 2019 RRS. Garrido said the lower average EEFORd was caused by the increased representation of combined cycle units and gas turbines.

The CBOT — the help PJM can expect from imports during peak loads — is estimated to increase pressure on the IRM. Garrido said imports from neighboring RTOs have decreased from 1.6% in 2019 to 1.5% in 2020.

“We’re getting a little less help from our neighbors,” Garrido said.

The FPR is essentially the same as 2019, Garrido said, coming in at 1.0865 (8.65%) instead of 1.086 the previous year.

Garrido said the study results will also be used in the 2022/23, 2023/24 and 2024/25 Base Residual Auctions (BRA). He said delays in the 2019 BRA for 2022/23 necessitated the use of data from the 2020 study.

The PJM and world load models used are based on the 2002-2014 period that were approved at the August PC meeting. (See “Load Model Selection,” PJM PC/TEAC Briefs: July 7, 2020.) Analysis from the 2020 PJM Load Forecast Report released in January was also used.

Erik Heinle of the D.C. Office of the People’s Counsel asked if the IRM and FPR would be updated after the first BRA was conducted to make sure the modeling is kept accurate.

Garrido said the driver of FPR is load uncertainty, so the results of the BRA wouldn’t matter for the FPR and does not necessitate a recalculation. Garrido said the recalculation is triggered by a new load forecast, which will be released in January.

Garrido also won a same-day endorsement after conducting a first read of the 2020/21 winter weekly reserve targets, which are slightly changed from last winter.

The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” according to the study. For the entire year, PJM sets the LOLE at one occurrence in 10 years.

Interconnection Queue Initiative

Ken Seiler, vice president of planning, discussed PJM’s plan for a series of workshops to explore ways to improve the efficiency and effectiveness of its interconnection queue process.

Seiler said more than 660,000 MW of generation requests has been studied since the inception of the interconnection process in 1999. More than 70,000 MW has been energized in that time.

“The process has served us well, but the process continues to change,” Seiler said. “We believe it’s time to take a look at some changes within the queue.”

Seiler said the interconnection process has seen many improvements over the years, including automation of tools and additional staffing. PJM currently has 122,000 MW in the interconnection queue with 88% of the megawatts made up of renewable generation sources.

The most recent queue that closed at the end of September has more than 560 projects, Seiler said, with more than 40,000 MW of energy requesting to be interconnected. Of the 560 projects, he said, 500 are either solar or storage.

Based on feedback from stakeholders and the increasing volume and size of the interconnection requests, Seiler said PJM decided it was time to take a “fresh look” at the interconnection process. Four workshops are proposed, including a review of the interconnection process, stakeholder presentations, PJM’s response to the stakeholder presentations and paths forward.

Seiler said the construct for the workshops would be based on federal policy and FERC Orders Indemnification Provision for PJM Tariff.) The first two workshops would take place before the end of the year.

Adrien Ford of Old Dominion Electric Cooperative asked if PJM is looking for feedback on how stakeholders should proceed at looking at the interconnection process or on things that need to be changed in the process.

Seiler said PJM is looking for both things that need to be changed and a process forward to make the changes. He said the RTO has already identified things that need to be changed, but there are also hidden problems that can be identified by stakeholders.

“We want to hear what everyone has to say and what objectives are there and what the end goal is,” Seiler said. “We want to hear everything before locking down a plan to move forward.”

Sharon Segner, vice president of LS Power, said she appreciated the idea of having the workshops but wondered why the RTO hadn’t drafted a problem statement and issue charge to start an official stakeholder process. Segner said it costs time and resources for members to address issues, but with a formal stakeholder process there’s an opportunity to change rules instead of simply having discussions.

Seiler said there hasn’t been a defined problem that would necessitate a solution, so PJM wanted to identify problems through a workshop first before initiating the stakeholder process.

Dave Anders of PJM said a similar workshop method was conducted when stakeholders began looking at the energy price formation issue in 2017. (See PJM Stakeholders Explore Price Formation, Seek Transparency.) Anders said the workshops are designed to expose areas of interest for members to address in the stakeholder process.

ELCC Data Submission

Andrew Levitt of PJM’s market design and economics department provided an overview of the effective load-carrying capability (ELCC) data submission requirements and the applicable deadlines for intermittent and limited duration resources.

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.

Members endorsed a joint stakeholder proposal at the September Markets and Reliability and Members committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. The proposal was endorsed over the objections of the Independent Market Monitor and other stakeholders who said the proposal was flawed and could have profound and unforeseen effects on the capacity market. (See ELCC Method Endorsed by PJM Stakeholders.)

PJM is attempting to make a FERC filing by Oct. 30 to satisfy a paper hearing procedure started last year to investigate whether the RTO’s 10-hour minimum run-time requirement for capacity storage resources is unjust and unreasonable. (See FERC Partially O K s PJM , SPP Order 841 Filings.)

Levitt said PJM needs data submittals from certain resource types by Nov. 1 to release ELCC results by December, the soonest FERC is likely to approve the October filing. Levitt said ELCC could be in place for the 2022/23 BRA.

Under the new rules:

“Immature” and planned solar and onshore wind projects that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012, based on site conditions and historical weather. PJM defines an “immature” resource as solar and onshore wind projects that came into service after June 1, 2012.
Immature and planned offshore wind, landfill gas and hydro without storage that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012.
All energy storage resources, hybrids and hydropower with non-pumped storage must provide relevant physical parameters, including MWh of storage.

Manual 14C Update

Mark Sims, PJM’s manager of infrastructure coordination, provided a first read of changes to Manual 14C: Generation and Transmission Interconnection Facility Construction.

Sims said minor changes are being proposed to Manual 14C as part of the biennial cover-to-cover review. Some of the changes include an update of the with the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5.

New sections on cost tracking for baseline projects and another for supplemental cost tracking are also being proposed, Sims said.

PJM will seek approval of the changes at the Nov. 4 PC meeting.

Transmission Expansion Advisory Committee

IEC Project Status

Questions over the status of the controversial Independence Energy Connection (IEC) transmission project were raised during a market efficiency presentation at the Oct. 6 TEAC meeting.

Nick Dumitriu, senior lead engineer for PJM, provided an update on the 2020/21 long-term market efficiency window. Dumitriu said the 2020 Market Efficiency Analysis Assumptions whitepaper was shared with the PJM Board of Managers for consideration at their Sept. 15 meeting.

Dumitriu said a preliminary market efficiency base case was posted Sept. 4, and a retooled base case is expected to be posted by the end of October. The final base case and congestion drivers will be posted in December before the start of the 2020/21 long-term window.

LS Power’s Sharon Segner asked if Transource Energy’s Independence Energy Connection running between Maryland and Pennsylvania will be examined by PJM during the reevaluation analysis scheduled to be completed between October and December as part of the Regional Transmission Expansion Plan (RTEP).

PJM — Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | ea

PJM selected the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid several times, determining in each round that the project remains the most effective way to reduce load costs. (See Updated: Transource Files Reconfigured Tx Project.)

Tim Horger of PJM said the RTO has continued to look at the status of the project and is “taking seriously” the project review.

The project received a certificate of public convenience and necessity (CPCN) from Maryland in July. (See Md. PSC OKs Independence Energy Connection Deal.)

PJM — Sharon Segner, LS Power | © *RTO Insider*

Horger said PJM is deferring a review of the project pending a ruling from the Pennsylvania Public Utility Commission. Transource is seeking the PUC’s approval of land acquisition, siting and construction for a 230-kV line in Franklin and York counties. The record closed with the filing of reply briefs in late September (Docket # A-2017-2640200).

Horger said an update on the project will be provided at the November TEAC meeting.

Segner said PJM has an Operating Agreement requirement to continue reevaluating projects until all required permits have been received.

Horger said the project is in a unique situation where a CPCN has been issued by one of the states involved in the permitting process. He said there are “a lot of moving parts” involved in the project, including reliability impacts.

“LS Power would maintain the position that you have an obligation to follow your Operating Agreement under all circumstances,” Segner said.

October 12, 2020

PSPS Relief Funds Not Spent as Intended, CPUC Says

A big part of $612 million intended to provide battery backup to homes in high fire-threat areas has been gobbled up by customers who use electricity to pump well water instead of helping the low-income and medically vulnerable residents it was meant for, the California Public Utilities Commission said Thursday.

The CPUC approved $830 million for its Self-Generation Incentive Program (SGIP) in January, with $612 million dedicated to “equity” and “equity resiliency” subsidies to aid residents who face repeated public safety power shutoffs (PSPS) by utilities to prevent wildfires. Thousands of the program’s targeted customers rely on electrically powered medical equipment to keep them alive. (See California PUC Devoting $1.2B to Self-generation.)

In its decision, the CPUC authorized investor-owned utilities to collect $166 million annually from ratepayers from 2020 to 2024. However, the commission did not include income criteria for the well-pump grants, which are part of the program, nor did it prevent customers from applying for funds for their vacation homes.

“We were seeing some second-home residents” receive the hefty grants, which pay the full cost of battery storage and solar cells to charge the units, said Commissioner Clifford Rechtschaffen.

The program’s “very clear focus was on helping the most vulnerable customers and communities in high fire-threat areas and ones that had been affected by multiple PSPS events,” Rechtschaffen said. “In particular, we targeted medical baseline customers, low-income customers and critical care facilities in disadvantaged communities.”

“The program provides very, very generous subsidies,” he said.

PSPS Relief Funds — Portable solar and batteries are meant to help medically vulnerable customers during power shutoffs under the state’s SGIP program. | *Edison International*

More than eight months after the decision took effect, with one of California’s worst fire seasons in full force, the state’s three large investor-owned utilities haven’t started reaching out to medically vulnerable customers, Rechtschaffen said.

Instead, developers of storage systems have targeted households with wells, regardless of income, and scooped up much of the funding that was supposed to last through 2024. Commissioner Martha Guzman Aceves said an informal analysis by her staff showed that only a small percentage of the storage contractors were licensed by the state.

Pacific Gas and Electric has already committed its $270 million share of the multi-year program and has hundreds of customers on a waiting list, Rechtschaffen said. Southern California Edison and San Diego Gas & Electric have doled out 50% and 60% of their shares, respectively, he said.

Half the applications have been for well-pump programs, while 30% have been for medically vulnerable customers, he said.

In his proposed decis i on, Rechtschaffen wrote that “if current trends continue, incentive awards to electric-pump … customers threaten to severely limit the … funds available to the many other types of eligible residential and non-residential customers.”

He proposed adopting income eligibility criteria for grants that haven’t already been funded, requiring households to show they fall below 80% of an area’s median income and that a well provides water for their primary residence.

“Requiring electric-pump well customers to meet the same income eligibility restrictions required of most other …. residential customers levels the playing field and helps ensure that other types of customers with critical resiliency needs have the opportunity to use equity resiliency budget funds,” he wrote.

The decision would apply the new criteria to grants that were submitted but not fully funded as of Aug. 17, when Rechtschaffen issued a letter advising utilities of the commission’s concerns.

Several commissioners expressed unease about applying new rules retroactively to those who have already filed for funding.

“We evidently made a serious omission” in not restricting the funds based on income, said Commissioner Genevieve Shiroma. But “to now go back and say, ‘Oops,’” and change the rules for pending applications, “I’m very uncomfortable with that,” she said.

CPUC President Marybel Batjer said she shared her colleagues’ worries about retroactivity but believes the program must be fixed.

“I’m very concerned about the equity program and it being oversubscribed so quickly when this was [planned] to be a three-year rollout,” Batjer said. “On balance, I think we have to address it. And I agree, Commissioner Rechtschaffen, with your assessment, but I do feel we need more consideration on this item.”

The commissioners voted unanimously to put off a decision until their next meeting on Oct. 22 so they could gather more information and weigh their options.

October 12, 2020

CAISO Adds Scarcity Pricing to Policy ‘Roadmap’

CAISO said Wednesday it plans to begin a stakeholder initiative on scarcity pricing with an issue paper and formal start in January.

The planned measure is a response to the energy emergencies of August and September, which required CAISO to order rolling blackouts Aug. 14-15. The state avoided additional blackouts only through extraordinary conservation measures, including removing Navy ships from shore power.

Scarcity pricing had been part of the ISO’s efforts to enhance its day-ahead market and extend the Western Energy Imbalance Market from a real-time to a day-ahead market. But the shortages caused a reassessment, Brad Cooper, the ISO’s senior manager of market design policy, said during a web conference on the annual update to CAISO’s three-year policy initiatives road m ap.

“Prompted by the conditions that occurred this summer, we’re now planning a separate initiative that we’re going to prioritize for next year that’s going to explore enhancements to our scarcity pricing provisions,” Cooper said.

“Recently FERC approved our … Order 831 compliance filing, which in some cases raises the bid cap to $2,000, but it does that in relationship to fuel costs,” Cooper said. “Last summer, a lot of times, prices outside the ISO went above $1,000, and that was not driven by fuel costs but by scarcity conditions. Those events really drove home the need to improve our market pricing in those scarcity conditions.”

In September, CAISO’s Market Surveillance Committee recommended the ISO pursue a scarcity pricing initiative to deal with the types of severe shortfalls seen in mid-August and over Labor Day weekend. (See CAISO MSC Urges Scarcity Pricing for Emergencies.)

“The experiences of mid-August again signal the urgency of such an initiative,” the committee said in its unanimous opinion, which it forwarded to the CAISO Board of Governors. “These conditions will likely grow more frequent, and the region is in need of a more coordinated approach to managing scarcity conditions.”

CAISO Scarcity Pricing — Scarcity pricing will be part of CAISO’s policy roadmap come January. | *CAISO*

Prices during the Western “heat storm” in August rose to $1,000/MWh or more and showed the need for higher-priced import offers during times of regional scarcity, the committee said. CAISO and market participants have noted that ICE prices for imported energy from neighboring states rose from $1,500 to $1,750 at the Palo Verde trading hub, which feeds into Southern California.

Scarcity pricing is triggered in markets when systems become so strained that reserve margins meant to protect the grid from collapse are threatened, as happened during the August blackouts.

A root cause analysis of the August blackouts by CAISO and other California agencies showed transmission constraints prevented ample, available imports from reaching the CAISO market and did not cite scarcity conditions. (See CAISO Says Constrained Tx Contributed to B l ackouts.)

Cooper said he hopes to see an issue paper released soon after Jan. 1.

“We haven’t worked out the detailed schedule yet, but that’s our goal,” he said.

Other major initiatives in the roadmap include resource adequacy enhancements, day-ahead market enhancements and an effort to the extend the Western Energy Imbalance Market from a real-time to a day-ahead market.

All three could help CAISO meet its reliability issues as it switches from a market largely dependent on natural gas generation to one that plans to meet its capacity requirements through renewable energy and storage, ISO staff members said during the web conference.

A high priority is addressing the state’s summer evening net demand peak, after solar power goes offline but demand remains high during heat waves. The energy emergencies of August and September occurred under such conditions.

“A robust RA program is critical to ensuring reliable resources are procured with the right operational attributes and are available to the CAISO in order to serve load in all hours,” said Lauren Carr, an infrastructure and regulatory policy specialist with the ISO who presented the RA initiative.

The 2021 roadmap of policy initiatives is expected to go before the Western EIM Governing Body and the CAISO Board of Governors in December.

October 11, 2020

PG&E Under Scrutiny in Deadly Zogg Fire

California fire investigators are looking at a distribution line as the possible cause of the Zogg Fire, which killed four residents and destroyed more than 200 structures southwest of Redding, Calif.

The 56,000-acre fire started on Sept. 27 near the rural Shasta County community of Igo. Among the victims were a 45-year-old mother and her 8-year-old daughter, who died trying to escape the flames.

A PG&E distribution line, the Girvan 1101 12-kV circuit, serves customers in the area of Zogg Mine Road and Jenny Bird Lane, where the fire began, PG&E said in an incident r e port to the California Public Utilities Commission on Friday.

Wildfire camera and satellite data on Sept. 27 showed “smoke, heat or signs of fire in that area between approximately 2:43 p.m. and 2:46 p.m.,” it said.

“A PG&E SmartMeter and a line recloser serving that area reported alarms and other activity between approximately 2:40 p.m. and 3:06 p.m. [on Sept. 27], when the line recloser de-energized that portion of the circuit,” PG&E said. “The data currently available to PG&E do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes.”

On Oct. 9, investigators with the California Department of Forestry and Fire Protection (CAL FIRE) told PG&E they had taken its equipment as part of their investigation of the Zogg Fire, PG&E said.

“PG&E is cooperating with CAL FIRE in its investigation,” the utility said. “This information is preliminary.”

CAL FIRE has not yet determined how the fire started, PG&E noted.

PG&E Zogg Fire — Searchers indentified at least four sets of human remains in the Zogg Fire. | *Shasta County Sheriff’s Office*

Involvement in another major fire would mark the fourth year in a row that PG&E equipment has been blamed for highly destructive conflagrations. Its equipment started the worst fires of the October 2017 “fire storm” in Napa and Sonoma counties and the November 2018 Camp Fire, which killed 85 people and destroyed the town of Paradise.

The company emerged from bankruptcy in June after agreeing to pay fire victims, local governments and insurers $25.5 billion in the 2017-18 fires and pleading guilty to 85 felonies stemming from the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan App r oved.)

CAL FIRE also determined that a PG&E transmission line started the Kincade Fire, which tore through Sonoma County wine country in October 2019.

The company has avoided blame so far for any of the major wildfires of 2020, one of the worst fire seasons on record. A series of massive fires sparked by lightning on Aug. 17-18 includes the August Complex, the first California wildfire to exceed 1 million acres. It was 67% contained as of Sunday, state and federal fire officials said.

In total, more than 8,000 wildfires have burned nearly 4 million acres in California this year.

Until Friday’s report — which PG&E also sent to the U.S. Securities and Exchange Commission — only one other investor-owned utility in California had fallen under suspicion for starting a major fire in 2020. (Calif. IOU s Escape Blame for Fires so Far.)

In a Sept. 15 r e port to the CPUC, Southern California Edison said the U.S. Forest Service had asked the utility to remove a section of its overhead conductor as part the agency’s investigation of the Bobcat Fire, still burning in the mountains and foothills northeast of Los Angeles.

SCE said it had experienced a “relay operation” on the 12-kV circuit at approximately the same time and in the same place as the fire started, but it contended that a fire camera had recorded smoke from the blaze prior to the incident.

“While USFS has not alleged that SCE facilities were involved in the ignition of the Bobcat Fire, SCE submits this report in an abundance of caution given USFS’ interest in retaining SCE facilities in connection with its investigation,” the utility told the CPUC.

October 11, 2020

PJM OC Briefs: Oct. 8, 2020

PJM stakeholders unanimously endorsed two manual changes at the Oct. 8 Operating Committee meeting.

Darrell Frogg, senior engineer of generation for PJM, reviewed updates to Manual 14D: Generator Operational Requirements.

Frogg said section 7.5.1 was changed to reflect that cold weather operational exercises will no longer be administered by PJM and instead be handled by generation owners. The RTO is recommending that generation owners self-schedule testing of resources that have not operated in eight weeks leading up to Dec. 1.

One change was made from the first read in September, Frogg said. Section 7.3, critical information and reporting requirements, calls for providing notification to PJM dispatchers at least 20 minutes prior to a change in state of each generating unit and will include any changes of more than 50 MW to the output of a self-scheduled resource that is not following the security-constrained economic dispatch (SCED) basepoint. Frogg said the change resulted from stakeholder questions.

Vince Stefanowicz, senior lead engineer of generation, reviewed updates to Manual 10: Pre-Scheduling Operations in a periodic review. The changes include several clarifying changes but nothing substantive, he said.

Stefanowicz said minor changes were made from the first read, including replacing the term “eDART Installed Capacity (eDART ICAP)” with the term “eDART Reportable MW” in Section 2.1, generation outage reporting overview. Stefanowicz said several stakeholders expressed concern over possible confusion with the capacity market term of ICAP.

Both manual updates will go to the Oct. 29 Markets and Reliability Committee meeting for first reads and final endorsements in November.

Day-ahead Schedule Reserve Update

David Kimmel, senior engineer of performance compliance, review e d the preliminary proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement. He said the numbers may slightly change when the measure is brought for final endorsement in November.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year average of under-forecasted load forecast error (LFE) and the three-year average of eDART forced outages.

Kimmel said the preliminary 2021 DASR requirement is 4.78%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.18% and the forced outage component of 2.6%.

Stakeholders will be asked to endorse the changes at the next OC meeting. The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.

Manual First Reads

Stakeholders heard several first reads of minor manual changes.

Maria Baptiste of PJM rev i ewed updates to Manual 3A: En e rgy Management System Model Updates and Quality Assurance. Baptiste said the changes include correcting grammatical mistakes and updating references to the behind-the-meter generation (BTMG) rules that took effect in September 2019. (See “Non-retail BTM Generation Rules Endorsed,” PJM MRC/MC Briefs: Sept. 2 6, 2019.)

Lagy Mathew of PJM revie w ed updates to Manual 3: Tran s mission Operations. Mathew said the changes featured minor clarifications, including defining the term “extra-high voltage (EHV)” lines as those equal to or greater than 345 kV.

Kevin Hatch of PJM reviewe d updates to Manual 12: Bala n cing Operations to address changes from the five-minute pricing and dispatch Market Implementation Committee special sessions. Hatch said PJM has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process.

Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”

Stakeholders will be asked to endorse the changes at the November OC meeting.

October 11, 2020

MISO Market Subcommittee Briefs: Oct. 8, 2020

MISO has at once rebranded and postponed its attempt to develop more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies.

The delay marks the third time MISO has pushed back an effort at combined cycle generation modeling. It also renamed the more involved process “multiple configuration resource” modeling.

MISO Director of Business and Digital Transformation Dhiman Chatterjee announced the further delay during an Oct. 8 Market Subcommittee call. MISO projects it will be able to model combined cycle interdependencies sometime late in 2025 at the earliest.

MISO first planned to put improved combined cycle modeling in place by 2020, then delayed until 2022, and again into mid-2023. The RTO said its current market platform couldn’t technically handle the software. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.)

MISO now says General Electric is delaying delivery of a new market clearing engine beyond original expectations, making combined cycle modeling an even more distant prospect.

Chatterjee also said MISO experts, already working on other priorities, will be further taxed by implementation of FERC Order 2222, which requires RTOs to enable aggregators of distributed resources the opportunity to compete in organized markets.

MISO has previously said it could save anywhere from $14 to $34 million annually if it implemented enhanced combined cycle modeling.

“This is beyond frustrating,” Xcel Energy’s Kari Hassler said. “I’m flabbergasted MISO continues to push this project out even though there are substantial savings to be had … This is a product that the entire footprint needs.”

Stakeholders asked if MISO could do something in the meantime to incrementally model combined cycle generators. Chatterjee said MISO is trying to be as transparent as possible about the challenges of implementing the modeling on its existing market platform.

“I just find it odd that [General Electric] said this is so complex of an ask when they’ve done something similar in SPP, and SPP has had it for about three years now. The complexity level is not extremely high,” Hassler said.

Chatterjee said SPP in fact encountered some technical difficulties when it introduced similar modeling. He also said SPP’s market clearing engine and interfaces are different from MISO’s.

“The tools are all customized, individualized for each RTO, and that’s why it’s so complex,” Chatterjee said.

“We’ll try to be ready, and if an opportunity presents itself, we’ll jump on that,” he added.

MISO Braces for 2nd Hurricane

At the time of the Oct. 8 meeting, Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said MISO was preparing for the then-Category 3 Hurricane Delta, the 25th named storm of the 2020 Atlantic hurricane season.

“Unless you’ve been living under a rock, you know we have another hurricane forming in the Gulf and headed to Louisiana,” McFarlane said.

While Hurricane Delta’s projected landfall is only about 10 miles east of where Hurricane Laura made landfall, McFarlane said the relatively good news was that the new storm is weaker and faster-moving. He also said a weekend landfall means less load to be possibly interrupted.

“So on a relative basis, that is a better situation,” McFarlane said.

MISO decla r e d conservative operations and a transmission advisory for its South region beginning Friday.

McFarlane warned that Entergy’s Louisiana territory is still experiencing transmission line outages from the last storm. Hurricane Laura’s landfall on Aug. 27 brought MISO’s first load-shed orders and widespread transmission damage. (See MISO Keeps Advisories in Effect a Week After L a ura.)

“Certainly, we’re not as resilient as we could be because of Hurricane Laura,” he said.

IMM Reassures Stakeholders on Coal Self-commitments

MISO’s Independent Market Monitor reiterated that most coal self-commitment decisions in the footprint are made prudently.

Last month, Monitor David Patton provided the Board of Directors with analysis showing that most of the footprint’s coal self-commitments are profitable. (See MISO IMM Rebuts Uneconomic Coal Com m itment Studies.) This time, he brought the results to stakeholders.

“We don’t see the level of concern that prior studies have indicated,” Patton told stakeholders.

The Union of Concerned Scientists has released its own study concluding that Xcel Energy, DTE Energy, Cleco Power and Consumers Energy repeatedly make uneconomic coal generation commitments, costing ratepayers. (See UCS Analysis Knocks Coal Self-commitme n ts.)

Patton said self-committed coal dispatch returned fewer revenues in 2019 only because all energy prices were lower across MISO.

MISO Communication System Still a Source of Frustration

MISO has conceded again that its communication system for emergency resources needs to be more user-friendly.

The acknowledgment came during a review of load-modifying resource performance for an early 2019 generation emergency.

Market participants use the nonpublic MISO Communication System (MCS) to update availability of their load-modifying resources for use in emergency conditions.

“I know the MCS is not the most beloved system, but it does provide important information to MISO,” MISO Corporate Counsel Jacob Krouse told stakeholders during an Oct. 7 Resource Adequacy Subcommittee conference call. MISO stakeholders have long criticized MCS as being clunky and difficult to navigate. (See Stakeholders: M ISO System Fix Too Late for Summer.)

MISO issued a maximum generation event Jan. 30-31, 2019, in its North and Central regions during a record cold snap. While it called on more than 180 LMRs, only 21% met their expected load reduction. MISO levied almost $3 million in penalties to underperforming LMRs, and nine market participants sought alternative dispute resolution that lasted until early 2020.

Krouse said during the course of the dispute resolution, market participants indicated they were confused about what data they needed to input into the MCS. Some market participants weren’t following MISO’s requirement to furnish the MCS with their most up-to-date LMR availability data either, Krouse said.

He also noted that the MCS contained “default values inconsistent with LMR registration information,” which was fixed with monthly updates.

Krouse said there was confusion among MISO market participants on whether scheduling instructions would come from the MCS or another MISO mode of communication.

Krouse said MISO is working on MCS improvements following discussion from the Demand Response and MCS Alignment Task Team, formed last year. Further MCS improvements might be rolled out in mid-2021.

October 11, 2020

MISO Lays Out Seasonal Capacity Options

MISO resource adequacy staff are considering multiple options in the RTO’s effort to implement a sub-annual capacity mechanism and define new reliability criteria.

MISO has said it could define unique seasonal system reliability requirements as a bulwark against its increasing emergency events outside summer months. The RTO’s analyses indicate an emerging wintertime loss-of-load risk. MISO said it could be in the position of facing a winter peaking situation when electrification picks up in 2035 and beyond.

The shift could prompt MISO to issue a sub-annual reserves requirement based on a seasonal resource adequacy construct.

Stakeholders attending a virtual Resource Adequacy Subcommittee meeting Oct. 7 asked if MISO would run a Planning Resource Auction (PRA) four times per year.

MISO Director of Research and Development Jessica Harrison said several options are under consideration, including an annual construct that reflects sub-annual needs, one annual auction with seasonal or monthly segments, multiple seasonal auctions or monthly auctions across the planning year.

MISO is also exploring the use of additional risk assessments beyond loss of load, including the expected unserved energy calculation, where MISO calculates the expected amount of energy when load is set to exceed generation.

Senior Manager of Resource Adequacy Coordination Lynn Hecker said there could be additional “administrative burden” on MISO and its members if it develops separate planning reserve requirements and resource accreditations for each season.

“That’s really on the MISO to-do list, to get a better idea of what — if any — administrative burden … the proposed construct options might create,” she said.

If MISO moves to a sub-annual version of the capacity auction, Hecker said it would reduce its focus on summer peak modeling and forecasting in favor of pinpointing multiple loss of load risk hours throughout the year, called resource adequacy hours. RA hours would likely occur in summer and winter.

Harrison said MISO must decide if it should rely more on forward-looking projections or historical data to establish accreditation and reserve requirements using resource adequacy hours.

“In a time of slower-paced change, that’s reasonable; in a time of fast-paced change, that’s less reasonable,” she said of historical data being a predictor of system conditions.

Seasonal capacity auctions might give way to more seasonal economic outages, MISO and members said.

Harrison said MISO will be mindful of a seasonal auction’s possible effect of corralling too many generation outages into shoulder seasons. The RTO might consider must-offer obligations on capacity resources for each sub-annual period.

“The more granular we go, the more complex it will be to implement,” Hecker said.

The State Authority Quandary

The possibility of new reliability requirements has MISO and members probing the complicated relationship between MISO and state authority.

Some stakeholders have said that a move toward additional reliability criteria could infringe on state jurisdiction over resource adequacy and that MISO’s existing annual local clearing requirements and planning reserve margin are sufficient for reliability needs. (See MISO Closer to Se a sonal Capacity, Reliability Reqs.)

To date, no states have ever requested that MISO increase or decrease a planning reserve margin, said MISO Managing Assistant General Counsel Michael Kessler.

The MISO Tariff stipulates that states have the authority to superse d e the RTO and set their own planning reserve margins, but they cannot change MISO’s local reliability requirements or local clearing requirements. MISO would have to incorporate a state-set planning reserve margin into its planning resource margin requirements if it received a special state margin figure for a set of jurisdictional utilities. The Tariff also prohibits MISO from developing a resource adequacy requirement that conflicts with “state reliability or safety standards.”

Kessler said there’s “no other entity … than a state authority” that can alter MISO’s planning reserve margin requirement.

Some stakeholders questioned why states wouldn’t also have at least some authority over local reliability requirements or local clearing requirements if resource adequacy is ultimately the states’ prerogative.

Six of MISO’s ten local resource zones include territory from two or more states.

“Our interpretation of the Tariff — our literal reading of it — is that states do not have the authority to create a different local reliability requirement other than the one established by MISO,” Kessler said.

If a state chooses to set a lower planning reserve margin, the local clearing requirement of a local resource zone would still apply, Kessler said, with MISO still responsible for procuring capacity up to the requirement. Costs of the extra capacity procurement would be uplifted to the entire MISO footprint.

WEC Energy Group’s Chris Plante asked whether states could use a different loss of load risk than MISO’s one-day-in-10-years standard. A state’s decision to rely on a two-days-in-10-years risk would seem to affect zonal clearing and reliability requirements, he said.

“We haven’t had to work through a scenario where some of these mechanics would apply,” Kessler said, adding that MISO could pursue a deeper legal analysis of interaction between the Tariff and state law.

Plante has noted that states already largely rely on MISO’s recommended margins to set their resource adequacy plans.

“I think states increasingly look to MISO to establish their reserve margins,” he said during a special Aug. 21 MISO teleconference to discuss resource availability.

Zone 7 Reliability Requirements Questioned

Stakeholders are expressing consternation over draft 2021/22 PRA reserve requirements. This year, MISO began factoring unavailable generation due to planned outages into its loss of load expectation (LOLE) modeling, result i ng in higher local reliability requirements for almost all local resource zones.

MISO is estimating it needs a 9.4% unforced capacity (UCAP) planning reserve margin, up from last year’s 8.9% figure. Translated into an installed capacity basis, MISO needs an 18.3% reserve margin requirement in 2021, compared with 18% last year. (See MISO Planning Reserve Margin t o Climb in 2020.)

The need for more padding is the most dramatic in Lower Michigan’s Zone 7. Some stakeholders said it was unfair that a few individuals in MISO’s modeling group could have such an outsized impact on capacity requirements.

Customized Energy Solutions’ Ted Kuhn asked for “guardrails” in the LOLE modeling inputs process so members could expect more stability in the results.

MISO said its LOLE analysis showed that Lower Michigan runs the risk of more peak demand days in September than other local resource zones.

MISO plans to publish final LOLE results by Nov. 1.

MISO seasonal capacity — MISO’s UCAP planning reserve margin 2011-2021 | *MISO*

For the 2020/21 planning year, Zone 7 cleared at a cost of new entry price of $257.53/MW-day, due in part to a new MISO rule banning capacity resources from taking extended outages. (See MISO: New Outage Rules Boosted M i ch. Capacity Prices.)

MISO Independent Market Monitor David Patton sa i d two resources in Zone 7 raked in a combined $154 million in the 2020/21 Planning Resource Auction despite being on outages over the entire summer.

“Those resources are effectively unavailable even though we pay them the same,” Patton said during an Oct. 8 Market Subcommittee conference call.

Patton said he has long calculated leaner capacity margins than MISO projects because of the RTO’s failure to incorporate outages into its capacity picture.

Meanwhile, Planning Adviser Davey Lopez said MISO’s short-term resource availability and need fixes were successful in freeing up an additional 5-10 GW in capacity over the past year, as planned.

MISO launched new Tariff rules early last year to introduce demand response capability testing, seasonal documentation of the availability of load-modifying resources and a 120-day notice period for planned generation outages. (See “Near-term Filings,” MISO to Continue Resourc e Adequacy Talks in 2019.) The rules were meant as a stopgap measure to buy the RTO more time to flesh out bigger ideas.

“We are striving to come up with longer term solutions. The first phase was intended to buy time,” Lopez said, adding that MISO must continue working on the longer-term PRA changes. “Capacity margins continue to erode.”