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May 13, 2020

NYISO Explores Hybrid Interconnection Processes

NYISO staff on Monday shared with stakeholders proposed interconnection processes for the market participation options the ISO has floated in its effort to integrate hybrid storage resources (HSRs) into its energy and capacity markets.

Kanchan Upadhyay and Amanda Myott, energy and capacity market design specialists, respectively, presented the ISO’s ideas to the Installed Capacity/Market Issues Working Group during a teleconference.

The ISO is proposing three interconnection options for HSRs:

Option 1 would allow HSRs to participate in the markets as distinct generators that share a point of interconnection;
Option 2 would enable participation through an aggregation model to allow resource components within the HSR that share a point of interconnection to bid as a single resource;
Option 3 would recognize an HSR as a self-managed energy storage resource that receives some or all of its energy from a connected renewable generator. (See NYISO Weighs Market Options for Hybrid Resources.)

Upadhyay covered the potential Energy Resource Interconnection Service (ERIS) process for HSRs. She said that for any new or proposed facilities proposing to interconnect as a hybrid resource, all resources behind the same point of interconnection (POI) could be included in a single interconnection request.

Distinct resources participating under Option 1 would have a separate ERIS for each unit, limited to the minimum of the capability of the inverters or the capability of the respective units.

NYISO Hybrid Interconnection — Examples of capacity resource interconnection service (CRIS) for hybrid storage resources. | *NYISO*

Under the current proposal, “the injection limit of the HSR project must be greater than or equal to the combined capability of all resources within the project,” Upadhyay said. “The ISO is still evaluating a potential enhancement that would enable this option to accommodate HSR projects with an injection limit that is less than the combined capability of its component resources.”

If existing market rules need to be modified, such changes will be developed for a potential vote at the Business Issues Committee by the end of 2020, Upadhyay said.

ERIS Limits

While HSR units may be studied under a single request, they may require separate interconnection agreements since they are treated separately in the market, Upadhyay said.

Aggregate hybrid resources participating under Option 2 would have a single, combined ERIS limited to the minimum of the capability of the inverters or the total capability of the combined units.

Hybrid ESRs under Option 3 would have a single, combined ERIS limited to the minimum of the capability of the inverter or the capability of the storage component of the hybrid resource.

Stakeholders stressed the importance of allowing developers to specify lower interconnection limits than the total potential output of the inverters.

“There could very well be configurations under Option 2 that have multiple inverters, solar paired with storage in quite a few combinations,” said Bill Acker, executive director of New York Battery and Energy Storage Technology Consortium (NY BEST). “I think it was mentioned earlier that there was possibly some work on looking at how that might work with a collection of inverters. We would hope that it wouldn’t necessarily have to be the sum of all the inverters, that you could actually set up a solution like that.”

CRIS Limits

Myott led the discussion on capacity resource interconnection service (CRIS) awards for HSRs, whereby each distinct resource within an HSR may request CRIS individually up to the nameplate of the resource.

Hybrid Interconnection — NYSERDA map shows distributed energy resources around New York City. | *NYISO*

In response to a stakeholder question on the potential enhancement to Option 1 to allocate CRIS between the two resources, Myott said NYISO is investigating the topic in the event they are able to implement an inverter limit.

“We’re thinking through all of the implications in terms of the application and how feasible implementing that would be, particularly in the short term [when] we’re trying to make this option accessible for these types of resources,” Myott said.

The ISO hopes to come back with more details soon but is not sure when, she said.

Aggregate hybrid resources under Option 2 may request CRIS up to the minimum of the inverter limit or nameplate of the components that comprise the HSR. Hybrid ESRs under Option 3 may request CRIS up to the minimum of the inverter limit or nameplate of the storage component, she said.

Myott closed by noting that the ISO is working on responses to various stakeholder questions, which will be addressed at a future working group. Topics include additional information about Northeast Power Coordinating Council reserve requirements; clarification on the “front-of-the-meter” definition; exploration of a possible thermal-plus-storage model; examples with numbers to understand how many megawatts can participate under each market (energy, reg, reserves, capacity) under each proposed option; and clarification on which options the ISO will pursue.

Mitigation Review

Market Design Specialist Sarah Carkner presented an upd a te on the ISO’s comprehensive review of buyer-side mitigation, which is part of the “Grid in Transition” initiative. (See N.Y. Lo o ks at Grid Transition Modeling, Reliability.)

F E RC in February narrowed the resources exempt from NYISO’s buyer-side market power mitigation (BSM) rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market. (See FERC Narrows NYISO Mitigati o n Exemptions.)

“We would like to move forward any concept as far as we can this year,” Carkner said. “Ideally, we would like to get the market design complete on any additional concepts for this project.”

May 13, 2020

Stakeholders Urge PJM: Plan `Grid of the Future’

Transmission owners’ supplemental projects totaled almost $3.4 billion in PJM in 2019, more than double the less than $1.5 billion in regionally planned baseline projects, PJM told the Transmission Expansion Advisory Committee Tuesday. It marked the fifth year out of the last six in which supplemental projects exceeded baseline projects.

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

“Supplemental projects undermine the strength of PJM as a regional planner,” LS Power’s Sharon Segner responded after a presen t ation by PJM’s Aaron Berner. “The question in our mind is: Is the right transmission being built?”

She was repeating a position that she and load-side stakeholders have made repeatedly in prior meetings — and that LS Power and dozens of other stakeholders made in a lett e r Tuesday to the PJM Board of Managers.

“Will the Grid of the Future be regionally or locally planned?” they asked. “We believe that the best way to reliably, cost effectively and holistically plan the Grid of the Future is through PJM’s independent regional planning process.”

Signing the letter, in addition to LS Power, were American Municipal Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition and numerous municipal utilities and state public advocates.

The stakeholders noted that the largest component of the spending on supplemental projects in 2018 was that identified by TOs as necessary due to end-of-life (EOL) conditions. “The statistics for 2019 also show that the vast majority of projects were based on claims of EOL conditions and were not subject to regional planning,” they said.

They called for Operating Agreement changes to make clear that PJM plans replacements for facilities identified by TOs as end-of-life, quoting from the PJM Board Reliability Committee’s Oct. 4, 2019 lett e r that said “PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility.”

“The transmission system in PJM needs to be developed with an eye toward the future, rather than simply rebuilding the grid of the past,” the stakeholders said. “We envision a future where PJM is able to combine drivers of transmission projects, namely public policy projects, with aging infrastructure replacement projects, to plan the Grid of the Future through a robust and transparent regional planning process.”

2019 supplemental project drivers | *PJM*

The stakeholders sent the letter to help the board understand their proposals scheduled for a vote at the May 28 Market and Reliability Committee meeting to change the OA to authorize PJM to direct the most cost-effective solution after the TO provides an EOL notification.

Three EOL proposals were given first reads at the April 30 MRC. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December. (See P J M End-of-life Tx Proposals Near Vote.)

In their letter, the stakeholders insisted their proposal “is consistent with” the Consolidated Transmission Owners Agreement — just one of the many points on which the TOs disagree with the stakeholders. The stakeholders also repeated their assertion that two FERC orders cited by TOs relating to “asset management” are irrelevant to their proposal.

Post contingency local load relief warnings (PCLLRW), wind curtailments and system congestion costs all have trended down in recent years, PJM says. | *PJM*

“Our collective hope is that PJM follows the direction set forth by [CEO Manu] Asthana and refrain from advocating particular policies and instead listens to all stakeholders and perspectives and brings expertise to bear to help achieve the three priorities of reliability, planning and market function for the most efficient delivery of power to [PJM’s] 65 million customers,” they said, inviting “constructive feedback” from the board.

The TOs are likely to make their own case to the board. But at the TEAC meeting, it was left to Alex Stern of Public Service Electric and Gas to get in the last word on their behalf.

“They’re excellent sound bites, but they don’t mesh with the project statistics [PJM] just showed,” Stern said of Segner’s comments.

During his presentation, Berner introduced new graphs showing that post contingency local load relief warnings (PCLLRW), wind curtailments and system congestion costs all have trended down in recent years.

“The data PJM presented in its Project Statistics review today demonstrates that PJM has been a strong regional planner,” Stern added after the meeting. “Particularly in the midst of the current pandemic, the region is worried about a lot of things but, thus far, fortunately, cost effective, reliable power has not been one of them.”

May 13, 2020

DER Modeling Survey Indicates Persistent Gaps

A recent survey of registered entities suggests the penetration of distributed energy resources such as rooftop solar installations and residential storage technology is growing, but more work is needed to ensure these facilities are properly accounted for in system modeling.

Speaking to NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group this week, Irina Green — a senior adviser for regional transmission at CAISO and co-lead of the SPIDER Modeling Subgroup — said the survey is intended to deliver a “high level” view of utilities’ approach to DER modeling. The survey was sent to 63 entities in December 2019; as of the Feb. 7 deadline, 44 had responded.

While this was a lower level of participation than the subgroup had hoped for, the team still felt the responses provided a useful cross-section, with many geographical regions and industry sectors represented. With respondents permitted to select multiple functions, participants included:

balancing authorities (20);
reliability coordinators (10);
planning coordinators (21);
transmission operators (34);
transmission owners (32);
transmission planners (35);
resource planners (26);
distribution operators (27); and
distribution providers (31).

“Some answered everything; some skipped some questions. But still, we got enough to be able to judge … what’s going on with DER modeling,” Green said.

DERs Set to Expand

Questions on the survey involved topics such as minimum and peak gross load in respondents’ service areas; technologies included in their definition of DER (such as solar PV, wind, battery storage, etc.); the share of DERs in gross load; and how they are modeled in load flow studies. Both retail and utility-scale DERs were addressed in the survey.

DER Modeling Survey — Rooftop solar panels in New York City | *Department of Energy*

Green cautioned against drawing substantive conclusions from the preliminary results, but she did point to some patterns in responses that the team found worth noting. While a majority of entities indicated they plan to expand the penetration of DERs on their system over the next five years, most reported they still do not incorporate DERs in their modeling, citing various reasons such as lack of data or tools or a belief that the impact of DERs is too small to account for.

Modeling subgroup members also suspect there is a higher occurrence of DERs tripping offline than entities are aware of; 17 of 27 respondents reported observing shifting peak or light hours of net load in their system because of increasing DER penetration levels, but only five said they had observed widespread tripping of DERs because of faults in operations. While it is too early to say for sure, Green said the fact that many of the same respondents said they lacked data to model DER behavior suggested that “the DER may have tripped, but the entity may not know that.”

DER Prediction Harder than Expected

The ability of utilities to predict the output of DERs, particularly in residential applications, is a topic of growing concern for the SPIDER group. Earlier this year, Thomas Bialek, the chief engineer for San Diego Gas & Electric, told the group that the behavior of SDG&E customers with rooftop PV systems is very different than system planners had expected. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.) Bialek also observed that such behind-the-meter services may be more vulnerable to cyberattacks than equipment that is directly controlled by utilities.

The modeling subgroup plans to continue reviewing responses and develop further studies to inform an eventual white paper. While the SPIDER leadership had originally intended to follow up this survey with another general questionnaire focused on specific modeling approaches, the revelation that most entities are not modeling DERs has led to suggestions that these plans be modified into a more targeted approach.

“I think we’ll have to re-evaluate that now based on some of [these] findings. … Do we want to do a separate survey when … we know what the answer will be?” said Ryan Quint, NERC’s lead engineer for advanced system analytics and modeling. “Maybe we can rethink that and … simply reach out to the folks that are modeling DERs and do some follow-up questions regarding studies. I think that’s a discussion that the modeling group will have here soon.”

May 13, 2020

PJM Monitor Finds Capacity Exit Costly for NJ

PJM‘s Independent Market Monitor released a report Wednesday concluding that New Jersey ratepayers would likely see costs increase if the state left the RTO’s capacity market and instituted a fixed resource requirement (FRR).

The New Jersey Board of Public Utilities opened a docket March 27 to investigate whether remaining in PJM’s capacity market under the expanded minimum offer price rule (MOPR) will impede Gov. Phil Murphy’s goals of 100% clean energy sources in the state by 2050 (Docket No. EO20030203). Comments are due May 20.

The BPU acted in response to FERC’s Dec. 19 order that expanded the MOPR to new and existing state-subsidized resources. The order granted exceptions for some existing resources: demand response, energy efficiency, self-supply and resources receiving payments under renewable portfolio standards.

The order could prevent New Jersey nuclear plants receiving zero-emission credits (ZECs) and future offshore wind generators from clearing the capacity market, leaving ratepayers paying twice for some capacity. Unless the order is overturned on appeal, New Jersey’s only alternative to the PJM capacity market is to provide its own capacity under the FRR.

Monitoring Analytics’ report concluded that a statewide FRR would increase costs by almost 30% if prices were at the PJM offer cap of $235.42/MW-day but only 2.4% if prices equaled the $186.16/MW-day weighted average price for the state in the 2021/22 Base Residual Auction held in 2018, the most recent auction.

Using similar assumptions, the Monitor found that ratepayers in an FRR for the PSEG locational deliverability area (LDA) would pay 6.4 to 27% more. Those in an FRR for the JCPL zone could save 2.1% or see prices rise by 28%. (The Monitor did not provide separate analyses for the AECO or RECO areas, which represent only 15% of the state’s load.)

PJM New Jersey capacity — PJM’s Independent Market Monitor analyzed a high- and low-price scenario for three different FRR regions in New Jersey. The high cost is based on PJM’s capacity offer cap, while the low price is set at the clearing prices in the most recent Base Residual Auction in 2018. | *Monitoring Analytics*

“Based on the analysis, the creation of a New Jersey FRR, a PSEG FRR or a JCPL FRR is likely to increase payments for capacity by customers in New Jersey,” the Monitor said.

The IMM’s analysis was requested by Stefanie Brand, director of the N.J. Division of Rate Counsel.

The BPU said Wednesday “it is premature to comment on the IMM’s report or anticipate what the results of the investigation may be.

“Staff has an obligation to review the comments filed in the docket and take any necessary action to continue the investigation (through further requests for comment, technical conferences, or hearings) before making recommendations for the board’s consideration,” the BPU said.

The Monitor said an FRR creates market power for the few local generation owners from whom generation must be purchased to meet reliability requirements. New Jersey has 15,005 MW of unforced capacity within its borders, 4,711 MW less than the 19,716 MW needed to meet its FRR reliability requirement.

“All participants in the New Jersey, JCPL and PSEG FRRs fail the one- and three-pivotal-supplier test, which reinforces the conclusion that there is structural market power in each case,” it said.

Because of the impact of market power, “even the higher estimates of the cost impact to the customers of New Jersey from the creation of an FRR are likely to be conservatively low,” the Monitor said. “If New Jersey were to subsidize any generating units, the subsidy costs would be in addition to the direct FRR costs.”

“Our basic overall point is that FRRs are not a panacea,” Monitoring Analytics President Joe Bowring said Wednesday during an RTO Insider webinar on the MOPR.

“FRR is a term that is really not very well defined, and the exact ratemaking process will be the result of negotiation. … There are, at the moment, no rules governing it; every state will do it their own way. But there is simply no reason to believe that this nonmarket approach … will provide the least-cost option for customers or provide incentives for renewables or for any form of energy you favor.”

The Monitor’s findings were similar to those of its previous analysis on the impact of Exelon’s Commonwealth Edison in Northern Illinois leaving the capacity market for an FRR and one on Maryland’s options.

Others have disputed those findings. Rob Gramlich, president of Grid Strategies, said FRRs won’t necessarily raise costs because they can use a lower reserve margin than PJM. (See PJM Monitor Defends FRR Analyses in MOPR Debate.)

Exelon is pushing legislation in the Illinois General Assembly to switch to the FRR. (See PSEG Turns Bullish on NJ FRR Option.)

Both Exelon and PSEG are trying to protect their nuclear units receiving state ZEC subsidies.

May 13, 2020

ERCOT’s Summer Reserve Margin up to 12.6%

ERCOT said Wednesday it still expects record demand this summer and the potential need for emergency measures, despite a drop in load from the COVID-19 pandemic’s continued effect on the Texas economy.

In making its final resource assessment for the summer months, the grid operator used data from Moody’s Analytics to drop its peak load forecast to 75.2 GW, almost 1.5 GW less than its preliminary assessment. However, the forecast is still higher than last August’s all-time record demand of 74.8 GW.

The pandemic has reduced weekly energy usage within ERCOT’s footprint by 3 to 4%.

“There is a lot of uncertainty in today’s world, but we are confident that Texas will still be hot this summer,” CEO Bill Magness said in a statement.

ERCOT Summer Reserve Margin — ERCOT’s peak load forecast through 2025 | *ERCOT*

Given the expected drop in demand and capacity additions since the last seasonal adequacy resource assessment (SARA), staff adjusted the summer reserve margin to 12.6%, up from 10.6%. Seven wind, solar and storage projects, totaling 276 MW of summer peak contributions, have begun commercial operations since the March SARA.

ERCOT said that even with 82.2 GW of capacity available this summer, energy emergency alerts are still possible should there be extreme weather, low wind generation or higher-than-normal generation outages. The grid operator called two EEAs last summer, when it had a reserve margin of 8.6%. Demand did not reach record peak levels either day, but wind production was unexpectedly low and thermal generation outages were high. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)

Pete Warnken, ERCOT’s manager of resource adequacy, said the risk of an emergency is still present but less likely with a reserve margin that is almost 50% higher. “We anticipate the risk is now lower with typical grid conditions,” he said.

The grid operator also released a preliminary SARA for the fall — 6.8 GW of additional capacity will help meet a predicted peak demand of almost 61 GW — and an updated capacity, demand and reserves (CDR) report.

The CDR report, a 10-year view of the ISO’s reserve capacity, uses pre-COVID load forecasts because of staff’s uncertainty over how the pandemic will affect future years. The report forecasts reserve margins of 17.3% and 19.7% in 2021 and 2022, respectively. ERCOT has approved 2.3 GW of resources for commercial operations since the December 2019 CDR, and staff have also included 6.5 GW of planned resources.

Preliminary data provided by generation project developers indicate the grid operator will have almost 18 GW of planned capacity additions for summer 2021, much of it renewables and some small, flexible gas-fired resources, ERCOT said.

May 13, 2020

MISO Targets Swifter Queue Processing

MISO is examining additional measures to shave the time its customers spend in the generation interconnection queue, this time focusing on the definitive planning phase (DPP) and negotiations on interconnection agreements.

The effort follows on MISO OK’d to Require Site Control in Queue.)

MISO now says its goal is to cut the time it takes to clear generation interconnection agreement (GIA) negotiations and the queue’s three-part DPP, where the RTO performs interconnection studies.

Currently, the DPP process alone takes about a year. Combined with the agreement negotiations, the timeline shoots up to about 505 days. MISO aims to have both processes take a year total.

“Three hundred sixty-five days is the goal, and we want to strive for efficiencies wherever possible,” interconnection engineer Cody Doll told stakeholders during a Interconnection Process Working Group conference call Tuesday. “Basically, we need to find a way to cut out 140 days from phase one to the end of negotiations.”

MISO’s interconnection queue contains 434 projects totaling 67.4 GW. It takes one project about three years to complete the queue.

Doll said if the process could be shortened to a year, it would help further MISO’s goal of aligning the separate planning processes for its interconnection queue and annual Transmission Expansion Plan. (See MISO Begins Bid to Merge Tx, Queue Planning.)

“This is basically a companion to that effort ongoing in other MISO forums,” Doll said.

MISO could crop about 60 days from phase one, Doll said, by getting a head start on its study models prior to the start of the DPP. He also said it could get a jump on developing mitigation plans by inputting in advance of the DPP some results from the screening analyses interconnection customers undergo before entering the queue. It could also probably devote less time to mitigation development, where the RTO recommends solutions to grid constraints, he said.

“The most projects drop out in phase one. It’s just the nature of the beast, so it might be unnecessary to have as many back-and-forths in phase one because it’s probably going to change,” Doll said. “Phase two and three are already pretty lean. I don’t think there’s really any fat to trim in phase two.”

In fact, he said, phase two has such an aggressive timeline that he recommends MISO add about 10 days to the existing 45-day timeline it gives itself to conduct system impact studies.

For phase three, Doll said MISO could begin using “engineering judgement” to begin some network upgrade facility studies immediately after the system impact study is complete and the project owner decides whether to stay in the queue. The current queue process prescribes a 40-day wait time between the owner’s decision point and the start of an upgrade study.

But Doll said MISO could prune the most time from the existing 150-day timeline for GIA negotiations. He said it envisions the process could take about 44 days.

“A lot of GIA negotiations can occur concurrently with the network upgrade facility study,” Doll explained.

He also said interconnection customers likely don’t need 60 days to decide to execute a drafted GIA, and transmission owners don’t need the allotted 30 days to decide the same.

Doll said that if everything goes according to plan, the new one-year process could potentially be introduced within two years. But he stressed that the plan so far is only a draft.

“We’re going to make edits on this based on comments and rehash some things,” Doll said.

May 12, 2020

UPDATE: SPP Extends COVID-19 Measures Through July

During SPP’s Board of Directors web meeting last month, one stakeholder commented on the number of beards grown by fellow sheltered-at-home stakeholders.

“One thing about growing a COVID-19 beard,” said Dave Osburn, Oklahoma Municipal Power Authority’s general manager, “I hope I don’t look like Billy Gibbons before this is over.”

Osburn may yet give ZZ Top’s front man a run for his facial follicles. On Friday, SPP said it was extending its suspension of its business travel and face-to-face meetings until Aug. 1 at the earliest.

The action will convert SPP’s July quarterly governance meetings to virtual webinars, as happened in April. The stakeholder groups last met in person in January, with their next face-to-face meetings scheduled in October.

“We look forward to the day we can conduct our meetings in person again, but we won’t until we’re certain we can do so safely,” SPP CEO Barbara Sugg said in a message to stakeholders. “We’ve now proven we can facilitate our stakeholder process virtually when necessary.”

The move comes as no surprise to Rob Gramlich, president of Grid Strategies.

“I find it hard to imagine people traveling for stakeholder meetings in July,” he said. “So many people call into these meetings that it would be hard to say having them face to face is essential or worth taking any risks about.”

On Monday, ERCOT followed suit and said that its stakeholder meetings will continue to operate remotely for “the foreseeable future.” The same timeline applies to visitors at the grid operator’s facilities, where only those employees who can’t work from home are in their offices.

ERCOT said it consulted with the Technical Advisory Committee and its subcommittee leadership. Together, they determined social distancing guidelines made it untenable to hold medium-to-large stakeholder meetings at the grid operator’s facilities without endangering the health of attendees.

TAC leadership has proposed procedure changes that will allow the committee to hold votes during conference calls. The group will discuss the changes during its May 27 information session.

ERCOT follows federal, state and local health agency guidance, along with epidemiologist recommendations in making its decisions.

SPP said it extended its suspension based on feedback from its member companies regarding their own pandemic response plans.

“The health and safety of our employees and their families remains a top priority for SPP and is key to our reliable delivery of services,” Sugg said, noting staff have not recorded any confirmed cases of COVID-19.

SPP staff have been working at home since mid-March. When it is safe to return to the office, as Sugg says, staff will do so in a staggered approach, a fifth of the employees at a time. (See “Sugg says RTO to Open Very Carefully in Months Ahead,” SPP Joint Quarterly Stakeholder Briefing: April 27, 2020.)

The RTO’s facilities and incident command structure teams will have personal protective equipment available and a supply line to restock when staff begin their phased returns to campus, Sugg said.

SPP’s systems remains reliable, though staff are tracking small but steady reductions in load, she said. Load is down 8 to 10% across the system compared to similar days and temperatures in recent years.

May 12, 2020

Dominion Undecided on FRR Option

While Exelon and Public Service Enterprise Group last week expressed support for pulling out of PJM’s capacity auction over the expanded minimum offer price rule (MOPR), Dominion Energy says it is undecided.

Exelon and PSEG officials discussed their views of the fixed resource requirement (FRR) option during their quarterly earnings calls. (See related stories, Clock Ticking on Exelon Illinois Nukes Under MOPR and PSEG Turns Bullish on NJ FRR Option.)

But Dominion told the Virginia State Corporation Commission in its proposed integrated resource plan May 1 that it is still evaluating the FRR alternative in response to FERC’s December order expanding the MOPR to new state-subsidized resources and “has made no decision at this time.”

“If the company were to elect FRR, it would have to do so in advance of the next RPM [Reliability Pricing Model] base auction,” Dominion said. “Typically, this election would need to happen about six months prior to that auction; however, due to the pending MOPR-related filings with FERC, the schedules may be compressed. The schedule depends on if, and when, FERC accepts PJM’s recent compliance filing.”

PJM currently estimates the next Base Residual Auction to occur in late 2020 or early 2021, about six and a half months after FERC rules on the RTO’s compliance filings.

FERC had previously exempted from MOPR self-supply resources owned by public power entities (cooperative or municipal utilities), vertically integrated utilities subject to traditional bundled rate regulation like Dominion and load-serving entities that serve retail customers.

But in the Dec. 19 order, FERC said new self-supply resources would no longer be exempt, ruling that they suppress capacity prices under PJM’s RPM. The commission said the self-supply exemption would be limited to resources that had either cleared the RPM or were in development and in PJM’s interconnection queue before the December order.

Dominion asked FERC to expand eligibility for the self-supply MOPR exemption to any resource that is planned under a self-supply entity’s IRP. (See Dominion: FERC MOPR Rulings Inconsistent on Self-supply.)

Dominion FRR — Dominion capacity position 2021 to 2035 | *Dominion Energy*

But in its April 16 rehearing order, the commission rejected Dominion’s request. “Integrated resource plans do not replace the PJM interconnection process; granting rehearing in this manner would expand the number of resources eligible for the exemption beyond those that reflect established investment decisions, to include resources that may not even be sufficiently developed to be in the PJM interconnection process at all,” FERC said. “We find that the demarcation clarified above is sufficient to recognize those resources that are sufficiently along in the interconnection process to warrant exemption under the commission’s stated goals.” (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)

Dominion Energy Virginia, which owns 27,100 MW of generation, is planning to build 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation. Its proposed IRP for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan, a response to Gov. Ralph Northam’s executive order on climate change and the Virginia Clean Economy Act, signed last month. (See Va. 1st Southern State with 100% Clean Energy Target.)

In its discussion of the FRR option, Dominion noted that American Electric Power, parent of Appalachian Power in Virginia and West Virginia, is “the only significant utility in PJM” to have adopted FRR.

“Because of its five-year minimum commitment requirement, risks to FRR election should be carefully weighed against the benefits,” Dominion told the SCC. “Risks include future environmental changes, regulatory changes, zonal constraints, and capacity and energy market changes. The potential benefits of FRR election include [a] lower required reserve margin and the absence of MOPR risk to new generation used to meet the load obligation.”

Under the expanded MOPR, Dominion said, “virtually all new generation resources will need to offer at net [cost of new entry] or an otherwise calculated market seller offer cap — which could be above the RPM market clearing price — resulting in $0 revenue for these uncleared resources.” (See MOPR Ruling Threatens to Upend Self-supply Mode l.)

Dominion said the reliability requirement for the FRR service area would be the forward load forecast plus the target reserve margin. “This is one of the primary differences between RPM and FRR, as the PJM coincident peak target reserve margin for FRR is forecasted to be approximately 15% — over 5% less than where the RPM market has been clearing recently. From a long-term planning perspective, this reserve margin requirement difference could be significant. If the company’s forecasted load was 20,000 MW, for each percent difference between [the] cleared reserve margin and target reserve margin, electing FRR would result in about a 200-MW reduction in [the] purchase requirement.”

But the company cautioned that “both the clearing price and the clearing reserve margin of the upcoming RPM forward capacity market remain highly uncertain.”

And it noted that capacity resources committed under an FRR plan will continue to be subject to the same Capacity Performance requirements as those committed through the RPM. “To the extent an LSE has capacity in excess of its load requirement, those excess capacity resources may not generate the same revenue as if offered into the RPM market,” it said.

May 12, 2020

Stakeholders Question High Mich. Capacity Prices

Stakeholders are asking if MISO’s new long-term generation outage policy played a role in driving up Michigan capacity prices in this year’s Planning Resource Auction.

While nearly all MISO local zones cleared under $7/MW-day in last month’s 2020/21 PRA, Lower Michigan’s Zone 7 cleared at the $257.53/MW-day cost of new entry price — 10 times the capacity price paid in the last planning year. (See Michigan Prices Soar in 8th MISO Capacity Auction.)

During a Resource Adequacy Subcommittee teleconference Wednesday, MISO Manager of Capacity Market Administration Eric Thoms told stakeholders that Zone 7 came up short of capacity to meet its local clearing requirement and had to import capacity, activating the CONE price.

Stakeholders asked if the Independent Market Monitor examined whether MISO’s new long-term outage rules might have been used as a façade by some Zone 7 resources to physically withhold capacity and drive up prices. The new rule stipulates that planning resources cannot offer into the auction if they plan to be on outage for longer than 90 days of the first 120 days of the planning year. MISO deems the first four, warm months of the planning year as the time when capacity availability is most critical. The RTO’s 2020/21 planning year begins June 1.

IMM staffer Michael Chiasson said the Monitor scrutinized long-term outages to make sure they were justified.

“We don’t want people to have outages in there that give them an excuse to not participate,” Chiasson said. “It’s kind of like a road with two ditches: Don’t participate if you shouldn’t, and participate if you should.”

Chiasson also said that some Zone 7 resources didn’t offer all the capacity they had, but the unoffered supply was below the Monitor’s conduct threshold of 50 MW per affiliated companies per zone. MISO’s 2017 rule applies a 50-MW physical withholding threshold to affiliated market participants collectively, rather than individually to each affiliated company.

Last year, the Monitor had to enforce market mitigation for economic withholding in Zone 7, resulting in a 1 cent/MW-day reduction in the Lower Peninsula. Zone 7 also cleared higher than all other zones last year, at $24.30/MW-day compared to $2.99/MW-day everywhere else.

Thoms said MISO will discuss how it approached its loss-of-load sensitivity analysis for Zone 7 at the June 10 RASC meeting. He said MISO would also investigate whether Zone 7 would have come up short in the last planning year had the long-term outage rule been in place at the time.

MISO’s 2020 Transmission Expansion Plan contains a special study into the increasingly tight capacity import and export limits (CILs/CELs) in Zone 7. The Michigan Public Service Commission requested the study, which will help the state “better understand the effects” of increasing either the CIL or CEL for Zone 7, according to MISO. (See Northern Focus for MTEP 20.)

Meanwhile, MISO says it wants to be more transparent in how it develops its loss-of-load expectation study.

“This is something we’re struggling with. … We’re trying to figure out how to get more stakeholder engagement earlier and up front. We want to make sure this process is meaningful,” RASC Chair Chris Plante said.

Customized Energy Solutions’ Ted Kuhn said the problem is that MISO makes a “fluffy,” introductory presentation one month, then comes back with LOLE study results in the next month.

“We never saw how this was being developed in the first place. … So something needs to change in how they’re developing their work products,” Kuhn said.

May 12, 2020

Test Phase Approaches for MISO Market Platform

MISO is ready to begin testing some of the capabilities of its new market platform as the effort to develop the system enters its fourth year, stakeholders learned last week.

“It’s really an exciting time for the program because we’re pivoting from foundational work to delivery,” MISO Senior IT Director Curtis Reister told stakeholders on a Market Subcommittee conference call Thursday.

Reister said members’ IT departments will soon begin testing MISO’s new market user interface software in a customer test environment.

MISO expects it will begin transitioning to the new interface by the third quarter of 2021, running the system in parallel to the old platform for several months to allow members to phase in the change before the old interface is officially retired in early 2022, Reister said.

The RTO reports that 291 companies currently use its market user interface.

MISO Market Platform — Curtis Reister, MISO | © *RTO Insider*

“It’s not like every member has to transition on the same day. This allows members to attempt to transition … and go back and forth as many times as needed,” Reister said.

Because of vendor delays, MISO now says it’s unsure if it can meet a self-imposed June deadline to demonstrate the operation of its private cloud using non-Critical Infrastructure Protection data. The new private cloud will house the modular platform, replacing the current server-based platform.

The RTO plans to migrate data to its new private cloud for testing and import modeling information to its one-shop model manager this year. (See “Private Cloud Prepped for New Market Platform,” MISO Board of Directors Briefs: Dec. 12, 2019.)

By the end of the year, MISO will have uploaded its operations data in the model manager, which is scheduled to go live next year, Reister said.

“Modeling is interwoven in a lot of MISO processes,” Reister said of the importance of a singular repository for the RTO’s many planning models. MISO currently relies on several different means to collect and validate grid information for modeling.

MISO said the contract and delivery date of work on its new day-ahead market clearing engine is currently under negotiations. Its goal is to have the existing platform and a version of the new platform running in parallel for testing purposes in 2021, paving the way for the eventual retirement of the old platform. The RTO hopes to have the new clearing engine in production in the third quarter of 2022.

MISO executives have said that the monolithic nature of the current market platform is a major limiting factor in adapting its market to accommodate new products that seek to incentivize availability of the RTO’s shifting resource mix.

“2020 is the fourth year of the program, and it represents a turn in focus of the work,” Vice President of Market System Enhancements Todd Ramey said during MISO Board Week in March. “Whereas the first three years of the program were primarily focused on extending the life of the legacy platform … this year we’re really making the switch to completing major projects and bringing some of this online.”