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December 23, 2025

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NEPOOL Participants Committee Briefs: Sept. 3, 2020

The New England Power Pool Participants Committee on Thursday approved a change to how ISO-NE accounts for energy efficiency in its gross load forecast reconstitution methodology.

The RTO said the change is needed to ensure gross load forecasts reflect the amount of EE that will clear in the Forward Capacity Auction and avoid counting EE resources with capacity supply obligations (CSOs) as both supply and demand. In the last several capacity auctions, it says, it has cleared less EE than was reconstituted.

The change, which was approved by the Reliability Committee in July, would set the quantity of load reconstitution based on a trend line reflecting historical measures of EE CSOs compared to the level of installed EE. (See “Wholesale Market Consequences of Gross Load Reconstitution Proposal,” NEPOOL Markets Committee Briefs: Aug. 11-13, 2020.)

The change received a 68% sector-weighted vote of the PC, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors. The change also was supported by about 55% of the Supplier sector, but only one-third of the Alternative Resources sector and only 20% of the Generation sector.

The PC had deferred action on the proposal in August following objections by the New England Power Generators Association (NEPGA), which contended that limiting reconstitution to the trend line based on the forecast could result in EE megawatts clearing in the FCA exceeding the level of forecast EE megawatts reconstituted for that auction.

NEPOOL
ISO-NE’s proposed change would set the quantity of energy efficiency load reconstitution based on a trend line reflecting historical measures of EE capacity supply obligations compared to the level of installed EE. | ISO-NE

The generators said capacity market prices could be suppressed if EE and other passive demand resources (PDRs) begin to clear more CSOs than reconstituted on the demand side.

NEPGA asked ISO-NE to not qualify EE as capacity supply above the level of EE reflected in the reconstituted peak load forecast, or add a constraint to prevent EE from clearing beyond the level reflected in the peak load forecast.

The RTO declined to endorse NEPGA’s proposal.

“The objective of the proposed PDR reconstitution methodology is to produce a reasonably accurate forecast of future PDR CSOs that will be correct on average, over time,” Robert Ethier, vice president of system planning, wrote in an Aug. 27 memo. “The ISO believes its proposal achieves that objective. The ISO will continue to observe the clearing of PDRs in the FCM [Forward Capacity Market] and, if it becomes apparent that modifications to the participation of PDRs in the FCM are necessary, then the ISO will return to the stakeholder process.”

The RTO hopes to implement the rule change for FCA 16.

‘Challenging’ August

ISO-NE Chief Operating Officer Vamsi Chadalavada briefed the committee on what he called a “challenging” August for RTO operations, a month that included Tropical Storm Isaias, which clobbered Connecticut and Western Massachusetts on Aug. 4, leaving 1.2 million customers without power following 32 transmission outages.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, Chadalavada approved his remarks afterward to clarify his presentation.]

ISO-NE declared an M/LCC 2 abnormal conditions alert at 3:40 p.m. on Aug. 4, which continued until 9 p.m. on Aug. 10. Scheduled generation and transmission outages were postponed where possible, and 1,200 MW of capacity was locked in Connecticut because of line outages.

Load fell well below forecasts after Tropical Storm Isaias clobbered Connecticut and Western Massachusetts on Aug. 4, leaving 1.2 million customers without power. | ISO-NE

The RTO also saw loads 1,000 to 2,000 MW above forecast during hot weather on Aug. 1, 9 and 10, requiring it to commit fast-start resources to maintain its operating reserves, Chadalavada said.

Aug. 9 presented an additional challenge because of an unplanned transmission outage in the Northeast Massachusetts (NEMA)/Boston area, high loads, the scheduled outage of lines 3163 and 3164 into Boston and resources that normally clear in merit in the day-ahead market not doing so.

The RTO was able to maintain all reliability standards by committing some resources and backing off others in the NEMA/Boston zone, Chadalavada said.

Daily net commitment period compensation (NCPC) for August was $2.9 million, up $1.2 million from July and up $1.3 million from August 2019.

NEPOOL
Average day-ahead and real-time ISO-NE Hub prices and natural gas prices: Aug. 1-26, 2020 | ISO-NE

First contingency payments totaled $2 million, up $500,000 from July, including $1.9 million paid to internal resources and $112,000 paid to external resources. Dispatch lost opportunity cost was $158,000, and rapid response pricing opportunity cost was $297,000.

Chadalavada said operators were performing “a balancing act” in deciding not to recall the outage of lines 3163 and 3164, saying that delaying too many scheduled outages would push more maintenance work into the peak maintenance season in the fall.

ISO-NE Proposes 2.5% Budget Increase

ISO-NE is proposing a $178.6 million operating budget for 2021, a $4.4 million (2.5%) increase excluding FERC Order 1000 funding and before depreciation.

Including depreciation and FERC Order 1000 funding, the increase is $3.2 million (1.6%).

The budgets include no increase to the full-time-equivalent employee headcount of 587.

Robert Ludlow, the RTO’s chief financial and compliance officer, said in a memo that the increase included inflation adjustments to compensation costs; implementation of the Energy Security Improvements (ESI) initiative; work related to renewable resources and emerging technologies; and cybersecurity and NERC Critical Infrastructure Protection (CIP) compliance.

The 2021 operating budget does not include funding for FERC Order 1000 costs because the RTO expects to underspend its Order 1000 budget by about $600,000 in 2020. Most spending on the issue in 2021 will be for legal expenses for protests and other filings.

The committee approved a modification to the ISO-NE Tariff’s true-up provision to allow the RTO to carry such unspent “special purpose” funding over to 2021 rather than having to return it.

The capital budget — which will fund ESI, the nGEM market clearing engine, nGEM software development (part II), cybersecurity improvements and a redesign of the CIP electronic security perimeter — will be unchanged from 2020 at $28 million.

Ludlow noted concerns of state officials that the RTO would not have enough internal resources to support the Future of the Grid initiative and that freezing the FTE headcount could have a negative impact on the Markets Development and System Planning departments.

“We shared that there was too much uncertainty regarding work related to the ‘Future of the Grid/Markets’ discussions to build in budgeted dollars and, to the extent additional resources or analyses are necessary, they will be funded through the contingency,” Ludlow wrote.

The New England States Committee on Electricity (NESCOE) also presented its proposed $2.4 million budget for next year, a $7,200 increase over 2020 and $113,000 below the $2.5 million projected in its five-year pro forma budget.

NESCOE said the reduction reflected “continued rebalance” of technical and legal spending and reductions in travel and professional services costs.

The PC will vote on the budgets at its October meeting.

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PJM Monitor Challenges MBRAs over Market Power

PJM’s Independent Market Monitor has opened another front in its bid to strengthen the RTO’s market power rules, filing challenges to the renewals of market-based rate authorizations (MBRAs) in 14 dockets.

The Monitor said the RTO’s current market power mitigation rules are insufficient to support the reauthorizations, reiterating arguments it made in its State of the Market reports for PJM and its February 2019 complaint alleging that the capacity market seller offer cap (MSOC) allows market power by some sellers (EL19-47).

Barring new rules, the Monitor said, FERC should require capacity market sellers to offer their resources at or below the “competitive capacity offer” — currently the avoidable-cost rate adjusted for expected Capacity Performance (CP) penalties and bonuses.

Energy market offers should be capped at or below the defined cost-based offer and required to submit operating parameters at least as flexible as the market’s defined unit-specific parameter limits, the Monitor said.

The Monitor filed protests Aug. 28 and 31 challenging triennial MBRA renewal requests by:

The Monitor noted that Order 861 allows intervenors to challenge MBRA applicants’ claims that they do not post horizontal market power concerns. “Analysis of PJM markets shows that all PJM sellers have the potential to have and exercise local market power at any time based on transmission constraints that may arise in the PJM market for a variety of reasons,” it wrote.

While PJM’s energy market results are “generally competitive,” the Monitor said, market power mitigation is often inadequate.

“Some sellers that fail the structural market power test — the three-pivotal-supplier test (TPS) — are able to set prices with a substantial markup over their cost-based offer,” it said. “Some sellers that fail the TPS test are able to operate, set prices and collect uplift payments with operating parameters that are less flexible than their defined parameter limits.”

No Action

FERC has not responded to the Monitor’s complaint over the MSOC, and there has been no substantive action in the docket since May 2019, when the IMM responded to PJM’s request to dismiss it.

PJM said the Monitor had failed to provide evidence that the cap — approved four years prior as part of the CP construct — and the results of Base Residual Auctions (BRAs) suddenly became unjust and unreasonable. (See PJM: Dismiss Monitor’s Offer Cap Complaint.)

PJM
PJM’s Independent Market Monitor contends ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 Base Residual Auction because of economic withholding encouraged by an inflated market seller offer cap. | PJM

The RTO said the commission’s order approving CP “explained that the default MSOC is just and reasonable because it reflects the amount that a competitive resource would accept to be committed as a capacity resource.”

The Monitor contends that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of economic withholding encouraged by an inflated MSOC. “The assertion that the system conditions have not ‘drastically changed’ since 2015 has no basis in fact and would surprise any objective observer of PJM markets,” it wrote in its answer. (See Monitor Defends Offer Cap Complaint.)

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Montana Hybrid Ruling Departs from PURPA Precedent

FERC last week broke with precedent in a decision that will hamstring the ability of renewables-plus-storage developers to optimize the output of their projects while still qualifying for treatment under the Public Utility Regulatory Policies Act.

The commission’s lone Democrat, Richard Glick, sharply dissented from the Sept. 1 ruling, which found that the 210-MW Broadview Solar hybrid project in Yellowstone County, Mont., cannot be certified as a PURPA qualifying facility because it exceeds the 80-MW cap on power production capability specified in the 1978 law. The commission found the project exceeded the cap despite the 80-MW limitation on its interconnection with the NorthWestern Energy transmission system (QF17-454).

Montana has been an especially contentious front for PURPA disputes in the West, where utilities contend the law requires them to integrate large volumes of QF renewable resources at contracted rates far above market rates. Montana’s Supreme Court last month ruled that the state’s Public Service Commission had “arbitrarily and unlawfully” reduced solar generators’ payments and contract lengths under PURPA. (See Montana Supreme Court Rebuffs PSC on PURPA.)

Broadview, a subsidiary of Broad Reach Power, stepped into the PURPA fray last year when it revised its QF application to reflect a gross capacity of 160 MW (up from 104.25 MW in the original 2016 application) and include 50 MW of energy storage, while maintaining a net capacity of 80 MW.

FERC noted the company explained that while its planned solar array “is sized greater than 80 MW to increase the facility’s capacity factor, the aggregate capacity of the solar array and battery storage system cannot exceed 80 MW net capacity due to” limitations on the project’s DC-to-AC inverters. Broadview said the increased power is not in a form to be transmitted to the grid without additional inverters.

The company contended that FERC’s finding in 1981’s Occidental Geothermal, Inc. that “a facility’s power production capacity is not necessarily determined by the nominal rating of even a key component of the facility” backs up its claim that the solar facility falls within the 80-MW limit.

Broadview also pointed to FERC’s determination in Malacha Power Project, Inc., a 1987 ruling that said that “the electric power production capacity of the facility is the capacity that the electric power production equipment delivers to the point of interconnection with the purchasing utility’s transmission system.”

Montana PURPA
| © RTO Insider

NorthWestern contested Broadview’s application, arguing that facility is not a single QF, putting it outside PURPA’s 80-MW capacity limit. It said the solar array and battery storage system are two distinct power production facilities at the same site because the 160-MW solar array exceeds the 80-MW net capacity limit and the battery qualifies separately as a small power QF.

The utility questioned Broadview’s interpretation of Occidental, contending that a facility’s individual components represent the most relevant calculation of its net capacity and that Occidental had actually determined that a facility could qualify as a QF only if it has the potential to produce more than 80 MW for limited periods because of circumstances outside the facility’s control.

The Edison Electric Institute argued that FERC should not allow generation operators to “artificially limit” the output from their facilities at a single location to stay within the 80-MW limit.

“With the growth of new technologies, such as batteries, and the increased sophistication of resources, EEI asks the commission to reconsider whether it is still appropriate to measure QF power production capacity based on net capacity as established in Occidental, rather than the rated capacity test that EEI asserts was initially intended by Congress,” FERC noted.

Occidental Reversal

FERC’s decision aligned with the complaints made by NorthWestern and EEI. While the commission acknowledged that its 40-year-old Occidental decision specified that a facility’s “send out” capability — and not the size of the project’s individual components — was the determining factor for PURPA eligibility, it now finds “there is a significant difference between (i) design capabilities that may incidentally or occasionally cross PURPA’s 80-MW threshold due to certain components or variances, such as fuel or ambient temperature, and (ii) a facility purposefully designed with a 160-MW solar array.”

“Broadview’s proposal represents a significant departure from any project that the commission has previously considered under a QF application,” FERC wrote. “That such a project arguably could satisfy the ‘send out’ analysis the commission applied in Occidental compels us to reconsider whether it is a facility’s ‘send out’ that is determinative of whether the facility complies with the 80-MW threshold established in PURPA.”

Based on that reconsideration, the commission determined that the Occidental finding that the maximum net output of the facility (or send-out) represents the facility’s power production capacity is inconsistent with the 80-MW power production capacity limit specified by PURPA and regulations.

“Re-examining Occidental and the potential such an analysis creates for the approval of projects that do not comply with the plain language of PURPA, we conclude that we have improperly focused on ‘output’ and ‘send out,’ instead of on ‘power production capacity,’ which is the standard established both in the statute and our regulations,” the commission wrote.

‘Preferred Outcome’

In his dissent, Commissioner Glick said that any “fair reading” of the PURPA statute and commission precedent would put Broadview’s power production capacity at 80 MW and make it eligible for QF status.

“The commission’s contrary determination will make QF status turn on the capacity of any one component of the facility, rather than the actual power production capacity of the facility itself. That conclusion finds no support in the statute, our precedent or common sense,” Glick wrote.

Glick agreed with Broadview that increasing the project’s power production capacity worked to improve its capacity factor, “meaning that the facility will, all else equal, generate a higher fraction of its total 80-MW capacity than it would with a smaller array … a result I would have thought the commission would be eager to encourage.”

He further called out the commission for a “break from precedent” that reaches “its preferred outcome.”

“On a broader level, I cannot help but express my concern that so casually upending settled precedent creates unnecessary uncertainty, making it hard for developers to know which precedents they can count on and which they cannot,” he said.

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CEC Explores Building Design Role in Decarbonization

Smart building design can play a central role in California’s drive to decarbonize its electricity system, but the massive stock of existing structures cannot be left out of the effort.

That was a key takeaway from a panel discussion Wednesday, part of the California Energy Commission’s two-day forum on “Reimagining Buildings for a Carbon Neutral Future.”

CEC Decarbonization

Andrew McAllister, CEC | California Energy Commission

“Decarbonizing our built environment is an opportunity to improve the relationship that our buildings have to the grid,” said Commissioner Andrew McAllister, the panel moderator.

But McAllister said he needed to “dispatch” one timely topic before kicking off the panel: “Our decarbonization goals were not the underlying reasons for” the rolling blackouts that shut power to millions of Californians during a mid-August heat wave. (See CAISO Provides More Details on Blackouts.)

Instead, the supply shortages prompting the Aug. 14-15 blackouts were caused by “momentary issues regarding weather” and California’s inability to import power from other Western states suffering under the same record-setting heat, McAllister said. (See Theories Abound over California Blackouts Cause.)

“It was really the reserve capacity that was not available when it was expected to be there,” he said. “The system actually mobilized new resources” during the system emergency.

McAllister’s defense of California’s ambitious environmental goals provided a transition into the theme of the panel: “Our buildings can be a decarbonization resource for the grid,” he said.

Buildings can be modified to “help in an aggregated way” to support grid reliability through load flexibility, demand response and use of distributed energy resources, McAllister said. He cited the example of OhmConnect, a DR provider that works with residential customers of Pacific Gas and Electric and Southern California Edison that helped stave off additional blackouts over Aug. 17-18 by calling on 250 MW of aggregated energy reductions.

“They have relationships with individual residential customers, and it’s a bidirectional, callable, fairly predictable resource at this point,” he said.

“How our buildings actually consume energy and how they behave is a topic of our time, and we will be in the coming months and years getting deep into that and developing resources to help that happen at scale,” McAllister said.

New and Old

New construction tends to dominate discussions around green building. McAllister asked his panelists to consider how existing buildings will represent the majority of structures needing decarbonization by midcentury, which in California will mean the electrification of appliances that still largely run on natural gas, such as furnaces, water heaters and stoves.

“Not that fully decarbonizing new construction is easy, but I think that it’s a different challenge and probably has fewer facets to it than our existing buildings,” he said.

McAllister pointed to one of those facets: that California’s most diverse populations live in existing housing stock, inserting a social and racial equity angle into the policy of decarbonizing housing.

CEC Decarbonization

Heather Rosenberg, Arup | California Energy Commission

“Certainly, anything that’s new should be held to the highest standard,” said Heather Rosenberg, an associate principal at sustainability consultant Arup. “That said, the places where there is most significant need is in existing buildings … particularly buildings in low-income communities and affordable housing.”

Rosenberg pointed to the difficulty of addressing decarbonizing homes in areas with low-income housing that have long suffered from “chronic” disinvestment.

“As we think about that and as we think about our communities, there is an opportunity to bring investment in and make sure that it’s done for the people who are in those communities without triggering further displacement and further degradation in places that really are requiring investment,” Rosenberg said.

“Some of our biggest projects that have pursued certification and used our platforms are renovation projects,” said Shawn Hesse, director of business development at the International Living Future Institute, which certifies structures that meet green standards.

“The question we pose all the time is [that] we’re not interested in something that’s a little less bad; we want to know what’s good,” Hesse said. “What does good look like? And you can ask that question for renovation projects as well.”

“I think we’re uniquely positioned here in California to have greater influence and impact on decarbonization, whether it’s existing or new buildings,” said Miranda Gardiner, senior vice president with design firm HKS. “We have Silicon Valley; we have so many higher [education] institutions — the [University of California] campuses that marry their new and existing construction with their master plans.”

CEC Decarbonization

Miranda Gardiner, HKS | California Energy Commission

Gardiner said she appreciates working with clients such as universities and health care providers because “they’re not into this kind of fast-fashion approach that some of our developer clients are, and they know their buildings are going to be operational/functional [and] they’re going to have occupants in them for the next 50 years, and they’re thinking about it long-term.”

“And when they look at their existing stock, [they ask the question], ‘How do I bring that up to speed with the new buildings?’” she said.

McAllister asked the panel how the building industry can attract financing for decarbonized buildings and appeal to investors that recognize the value of “co-benefits” from greater building efficiencies. Those benefits can include lower expenses, better indoor air quality and the livability improvements from an overall higher standard of design.

Rosenberg said Arup is currently working with a major nonprofit developer of affordable housing to create metrics for co-benefits in a way that could drive investment from socially conscious investors.

“And then you have to think about how to bundle projects, because at the individual project level, it’s not enough to attract investment. You need a bunch of them, and then what’s the [return on investment]?” she said.

“We aren’t missing the technology. We aren’t missing the recognition of the climate imperative,” Hesse said. “What we’re missing is the ability to align the financing with these projects to actually turn them into reality.”

Rosenberg said the economic signals for decarbonization will not be strong enough until there’s a “real” price on carbon, which will likely require a “regulatory push.”

None of the panelists could answer McAllister’s question about what carbon price would actually “flip the switch” and bring investment into building decarbonization.

“We really need to … unpack that,” McAllister said.

Decentralized Resilience

Decarbonization is currently seen as “mitigation strategy” for climate change, but it can move beyond that role to reshape the relationship between the built environment and the electricity grid, Rosenberg said.

“It also can become, if we design it right, an adaptation strategy where we are reducing our dependence on a completely centralized and fairly rigid grid and bringing diversity, flexibility, durability [and] redundancy into our energy system in some new and creative ways. But it only works if you design it that way,” Rosenberg said.

The California utility policy of public safety power shutoffs (PSPS) to avoid sparking wildfires “has changed the way that people think about power reliability,” she said. PSPS is driving interest in microgrids by businesses such as airports, hospitals and data centers, for whom the momentary switching to backup power is too disruptive.

While those organizations previously couldn’t justify the cost of a microgrid based on the benefits of having flexible load or providing DR, the value of having “constant power” now makes the idea “pencil” out — “and that’s been a really big shift in the state,” Rosenberg said.

Shawn Hesse, International Living Future Institute | California Energy Commission

Hesse echoed the theme of reducing dependence on a centralized grid, offering a different take on the notion of resilience.

“As great as new technology is, and the ability to do instantaneous demand shifting, there are some pretty basic things that allow us to design projects to need less energy in the first place,” Hesse said.

He recounted a story about a project team from his company meeting in a “living” — or sustainably designed — building when the grid went down.

“No one noticed,” he said, because the building was designed based on passive energy principles, being primarily lit by daylight and having a natural ventilation system.

“When it does need those active systems, those systems are powered through on-site renewables,” Hesse said.

“Designing out the reliance on those kinds of systems is kind of the primary resilience strategy that allows us to do so many things all at once,” he continued. “I don’t want to leave that out of the conversation — that there’s actually a huge role to play in terms of the design community, particularly, in really doing our own best practice and not relying so much on grid administrators.”

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MISO Keeps Advisories in Effect a Week After Laura

MISO staff continue to keep advisories in effect and compile data on the MISO South emergency and subsequent rolling blackouts caused last week by Hurricane Laura.

The RTO said Laura was the strongest storm to hit Louisiana in 150 years.

“The southeastern Texas and southwestern Louisiana areas of the MISO footprint sustained substantial damage to the transmission facilities under MISO’s functional control, as well as to interconnected generation and distribution facilities, requiring careful and deliberate focus on maintaining system stability,” the RTO said.

MISO Advisories
Restoration worker handling new wires | Entergy

Laura’s path of destruction Aug. 27 caused MISO to direct Entergy to employ periodic power outages in the western half of the West of the Atchafalaya Basin (WOTAB) load pocket that spans the Texas-Louisiana border. (See MISO Enacts Rolling Blackouts in Laura Aftermath.)

MISO said that as a result of the widespread grid damage, the area’s constraint locations have temporarily changed. It said it is investigating the locations to include them in modeling.

“It is important that any unique restoration system conditions are captured correctly in MISO’s market models and the bids and offers they clear, to properly incentivize additional, economic generation as part of the restoration efforts,” MISO said.

The grid operator reported that $3,500/MWh value of lost load pricing was in effect for some of the WOTAB’s commercial nodes from 11:40 a.m. to 10:55 p.m. ET on Aug. 27.

MISO has put standing capacity and transmission advisories in place for the areas affected by the hurricane, warning members that generation and transmission capacity could become scarce as restoration work continues. It also canceled a monthly training drill on firm load shedding planned for Sept. 2 in MISO South because of an extended conservative operations declaration through Monday in some areas.

Chris Miller, FERC liaison to MISO, thanked MISO South members for their restoration efforts along the Gulf of Mexico and surrounding areas.

“I know it’s a big event. It’s an ongoing situation, and I want to give a hearty ‘thank you’ to everyone working to get power back to people,” Miller said during a Reliability Subcommittee meeting Thursday.

Entergy said the bulk of lingering outages lies in its Louisiana territory. The utility said that as of Thursday, it has restored 81% of the 616,000 power outages caused by Laura; however, it also said that more than 108,000 of the 271,000 Louisiana customers affected by Laura remain without electricity. The company said nearly all the 291,300 Texas customers affected by the hurricane would be restored by Friday.

MISO Advisories
Damaged transmission tower caused by Hurricane Laura | Entergy

Entergy said it is committed to a swift restoration but warned that customers in the city of Lake Charles and Cameron and Calcasieu parishes will “face weeks” without power.

“Our damage assessments indicate catastrophic damage to our electrical infrastructure. We expect the recovery to be as difficult and challenging as we have ever faced in the past,” Entergy said. “The damage from Hurricane Laura’s historic intensity caused catastrophic damage to the Entergy system across Louisiana and Texas. The eye wall, which brings the most damaging winds and intense rainfall, passed directly over Lake Charles, La., causing wide-spread damage to that area and our system.”

Entergy reported 219 out-of-service transmission lines, 292 damaged substations and sizable distribution system damage.

SPP CEO Barbara Sugg said before, during and after the storm’s landfall, there was coordination among SPP, MISO, ERCOT, regulators, American Electric Power and the Edison Electric Institute.

“Together, we addressed voltage and severe loading issues, monitored required load sheds and mitigated the risk of major, potentially catastrophic outages both during the event and through restoration efforts,” Sugg said in an emailed update. “Certainly, load shed events are unfortunate and undesirable. However, I’m proud of the interregional coordination to protect the bulk electric system.”

She said she has received “messages of gratitude” from MISO leadership.

More Detail on July Emergency

Meanwhile, MISO staff last week released more information on the July 7 maximum generation event that affected its North and Central regions.

Speaking during the RSC meeting, MISO System Operations Senior Adviser Gerald Rusin said the RTO may not have needed to enact emergency measures. He said MISO’s North and Central regions were spared from more intense heat by widespread pop-up thunderstorms that began around 1 p.m. July 7. While generation and load-modifying resources’ emergency ratings were available to meet forecasted load, Rusin said LMR use wasn’t necessary. (See Max Gen Event Managed Efficiently, MISO Says.)

“At the time that we made the declaration, the numbers were pointing that way,” he said, citing forecasted temperatures in the low 90s in the North and Central regions and a “near peak” combined load of 88.5 GW for the two regions.

COVID-19 pandemic load profiles that continue to be unpredictable also contributed to some uncertainty during the event, Rusin said. He said unplanned generation outages have been steadily increasing since April, possibly because of the pandemic. By July, unplanned outages had risen to more than 10 GW, uncharacteristically high for the month known for peak demand, he said.

“We need to see how this plays out in the months to come to see if the true effects of COVID caused the pattern to persist in this way,” Rusin said.

Ultimately, systemwide MISO load peaked at 114 GW for the month on July 8. The RTO experienced an average 88.4-GW load during the month, slightly higher than 2019’s 88.1-GW systemwide average.

Executive Director of Real-Time Operations Rob Benbow said MISO will update its termination declarations after some stakeholders said it wasn’t completely clear through RTO communications which emergency steps ended and when during the July event.

“We want to make sure it’s clear and that everyone is on the same page as we step down protocols,” Benbow said.

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GridLiance Acquires Tx Facilities in Kansas

GridLiance said last week its High Plains subsidiary has acquired a 65% ownership stake in the 69-kV transmission system and related substation equipment of the city of Winfield, Kan.

The transaction marks the company’s first co‐ownership of transmission assets with a municipal utility under a development agreement with Kansas Power Pool, a municipal energy agency that provides energy and transmission services to Winfield and 30 other municipalities in Kansas.

“The successful closing of this transaction is an important step in bringing improved transmission reliability to Winfield customers and the region,” GridLiance CEO Calvin Crowder said in a press release. “It is another example of our long‐term commitment to invest in the electric grid and ensure the fair treatment of all transmission consumers.”

The city will retain 35% ownership in the facilities and will be responsible for their maintenance. Winfield will continue to own its electric distribution assets and continue to provide retail electric service in return for a franchise fee and economic development and community support funds from GridLiance. Financial terms of the deal were not announced.

GridLiance
GridLiance substation | GridLiance

The Dallas-based independent electric utility holding company and Winfield have already begun to relocate transmission lines damaged by years of flooding on the Walnut River. The work is expected to be completed by the end of the year.

“Joining forces with GridLiance will ensure we will continue to [provide reliable electric service] for the long term,” Winfield Mayor Phil Jarvis said. “We are already seeing the benefits of our collaboration with GridLiance.”

The transaction was completed once FERC in late August accepted SPP Tariff revisions adding an annual transmission revenue requirement reflecting GridLiance High Plains’ addition as a joint owner of Winfield’s transmission facilities (ER20-2195).

The acquisition is GridLiance’s second of the year. In February, its gained access to the GridLiance Gains Entry into MISO.)

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SPP Briefs: Week of Aug. 31, 2020

SPP said last week it will begin allowing staff to return to its Little Rock, Ark., corporate headquarters in October, although the move is dependent upon “our community meeting certain milestones for health and safety.”

The transition back to the office is scheduled to begin Oct. 5. SPP will used a phased approach, with 20% of the staff returning at a time. The grid operator in mid-March sent home its non-operations personnel, though some individuals have returned in recent weeks.

“We will continue best practices to keep our employees healthy and provide our essential services,” CEO Barbara Sugg said in an email to stakeholders.

The RTO’s Board of Directors and other committees will continue to meet virtually through at least January. The board and Markets and Operations Policy Committee last met in person in January.

SPP
SPP plans to allow staff back to its corporate offices in October. | WER Architects

The White House Coronavirus Task Force last week placed Arkansas in the “red zone,” which recommends indoor dining be capped at 25% capacity and that bars be closed. The state on Friday reported a record 1,094 confirmed COVID-19 cases and 12 deaths, raising its totals to 64,174 and 873, respectively.

Sugg also took time to remark on SPP’s “collective progress” this year. Load has returned to pre-pandemic levels, while staff and stakeholders continue to prepare to launch the RTO’s Western Energy Imbalance Service market and conduct other strategic initiatives.

“Together we have navigated temporary and lasting changes to the way we work. … I know together, we stand ready to meet new energy challenges that arise,” she wrote.

Sugg said SPP is “working through the aftermath of Hurricane Laura,” which affected its footprint and those of neighbors ERCOT and MISO. The RTO has also supported western grid reliability by coordinating with CAISO, members and customers to ensure resources are available.

“We learn from each event we experience and take the opportunity to improve our own processes while also communicating with our peers about lessons learned from their perspective,” she said.

“Take good care, and please wear a mask,” Sugg said, in closing her email.

SPC Takes Look at Tx Planning

The Strategic Planning Committee is forming a task force — cumbersomely named the Strategic & Creative Re-Engineering of Integrated Planning Team (SCRIPT) — to evaluate all of SPP’s transmission planning and applicable cost allocation processes.

SCRIPT comprises 11 SPC and Members Committee representatives and will add a soon-to-be-named member from the Regional State Committee. Chaired by Director Mark Crisson, the group will report to the board and provide updates to the three committees.

“This is going to be a really important initiative that has the potential to have a major strategic impact on the organization,” Crisson said during an Aug. 31 SPC education session on transmission planning.

SPP
SPP’s transmission-planning roadmap extends into 2023. | SPP

During the session, SPP staff ran the committee through its planning initiatives and processes, including:

  • centralized coordinated process and integrated transmission planning;
  • cost-allocation alignment;
  • decision quality;
  • risk-based planning;
  • regional fuel mix;
  • generator interconnection (GI) improvements; and
  • model reduction.

SPP has seven planning departments. Staff conduct seven different planning studies, as well as compliance, seams and ad hoc studies. They are also responsible for resource adequacy analysis and model builds.

SCRIPT is expected to consider options to redesign those processes and produce a report with high-level recommendations by September 2021.

“We need to see how we can step back and integrate all the transmission functions we have,” said Casey Cathey, SPP’s director of system planning. “Everything we do has a reason. We have a reason for a GI process. We have a reason for reliability planning. The question is, how can we do it better?”

Staff are working on a planning roadmap to be presented to the board in January. SCRIPT is an important first step, Vice President of Engineering Antoine Lucas said.

“We will be looking for the SCRIPT to prioritize those initiatives and drive solutions through the working groups in an effective manner,” he said.

The SPC has also created the Energy Storage Resource Task Force to determine the strategic use of storage as capacity and in potential support of the grid. The task force is scheduled to complete its work in the first quarter of 2021.

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PG&E Blacks out 500K Residents to Prevent Fires

Pacific Gas and Electric turned off power starting Monday night to nearly half a million residents two minutes after CAISO effectively ended its four-day blackout watch.

Strained capacity during a Western heat wave and lightning-sparked wildfires caused CAISO to issue blackout warnings over the long Labor Day weekend. (See CAISO Avoids Blackouts amid Brutal Heat, Fires.) High winds and the fear of utility-sparked wildfires drove PG&E’s intentional blackouts Monday night.

“Pacific Gas and Electric Co. has begun the process of power de-energization of numerous electrical lines as part of a public safety power shutoff [PSPS] due to severe weather conditions,” the utility said in a news release at 9:06 p.m.

The PSPS event affects 172,000 customers, or about 499,000 residents, in portions of 22 counties in the Sierra Nevada foothills, the Sacramento Valley and the northern San Francisco Bay Area.

At 9:04 p.m., CAISO relaxed its alert status, telling customers they no longer had to conserve power because of extreme heat and insufficient resources. The ISO declared Stage 2 emergencies Saturday and Sunday while warning it would call for rolling blackouts. It managed to avoid outages largely because of consumer conservation and help from neighboring utilities.

PG&E blackouts
| PG&E

The heat wave that brought record temperatures to Los Angeles dissipated Monday as a high-pressure ridge gave way to offshore winds along the California coast and to cooler air flowing into the Western U.S. from Canada, the National Weather Service said.

By Tuesday morning, strong northeast winds were blowing across interior Northern California — the same conditions that spread catastrophic fires ignited by utility equipment during the past three fire seasons. NWS issued a red-flag warning through Wednesday morning based on low humidity and winds that it said would gust from 35 to 55 mph in the mountains and foothills of Northern California.

Dry vegetation and the rush of air from the north meant a “large portion of the Western U.S. will experience another day of critical to extreme fire weather conditions — meaning any ongoing fires or new starts could experience very dangerous fire behavior and spread,” the weather service said.

In Oregon, Portland General Electric instituted the state’s first PSPS on Monday as high winds buffeted the Mount Hood area east of Portland. About 5,000 customers were intentionally blacked out, while 100,000 Portland-area customers lost power as wind knocked down tree limbs and power lines. (See High Fire Danger Prompts First Oregon PSPS Event.)

Smoke from wildfires in eastern Oregon and throughout California continued pouring into urban areas, producing a noxious mix of wind-whipped smoke.

Southern California will feel the winds next, the weather service said. Santa Ana winds, notorious for spreading wildfires, will blow into the Los Angeles area through Wednesday night. NWS issued red-flag warnings until 8 p.m. Wednesday.

“Fuels, after this historic heat wave, will be at critical levels as we enter into the Santa Ana wind event,” NWS warned.

Southern California Edison said Tuesday afternoon it could shut off power to 55,000 customers in six counties to prevent wildfires, but it had not yet instituted a PSPS as of press time.

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NERC Updating Winter Prep Guide to Account for Wind

NERC last week previewed several changes it is making to its Generating Unit Winter Weather Readiness guideline to ensure balancing authorities are aware of wind turbines’ low-temperature cutoffs.

The temperature at which a wind generator must shut down to avoid turbine blade damage can vary, Richard Hackman, NERC senior event analysis adviser, told attendees of a webinar on preparing for the coming winter. For sensitive components including lubricants and uninterruptible power supply (UPS) batteries, it generally ranges from -30 to -10 degrees Fahrenheit. The ERO now wants generators to keep their BAs advised of that cutoff before an expected “winter weather event,” along with any changes to availability, capacity or other operating limitations.

“Those things need to be known by balancing authorities so that they can take them into account,” Hackman said. “These things are expected to run under certain conditions, and if the weather forecast says it’s going to be too cold to operate those generators, people need to be able to plan on what they’re going to use instead. And that needs to be communicated well in advance.”

One attendee asked whether BAs should already know the low-temperature cutoffs for their wind units.

“You would hope that they do, but last time we ran into an issue with wind turbine cutoffs, the BA got a little bit surprised,” Hackman said. “Some of the wind generation owners were also surprised by the cutoffs. Apparently, they weren’t that familiar with them.”

NERC winter prep
Preliminary reserve margins and reference levels for winter 2020/21 | NERC

He referenced the cold-weather event of January 2019, when MISO: Winter Emergency Another Signal for Grid Ops Change.)

NERC also added several “possible problem areas” that operators should check on their wind units before winter arrives:

  • lube oil and greases, which have temperature limits themselves, for mechanical equipment;
  • lead acid batteries or other UPS systems in exposed areas; and
  • adequacy and functionality of heat tracing, insulation and temperature-responsive ventilation.

Hackman said the last item is “actually for everybody out there and not just the wind turbines. … [It] is one that should have been applied a long time ago.”

One other change to the document will also apply to all resource types: NERC is advising generators to “schedule any needed cold weather-related inspections, repairs and ‘winterization’ work” for before the National Oceanic and Atmospheric Administration’s first frost dates for their areas. NOAA defines this as the earliest possible date that an area will experience temperatures below 32 F. For parts of the Upper Midwest, this can be as early as Sept. 1. Similarly, the ERO wants generators to wait until after their last frost dates to begin undoing their winterization.

NERC winter prep
| Shutterstock

Other minor updates include replacing references to the old Operating, Planning and Critical Infrastructure committees with the new Reliability and Security Technical Committee, as well as a page of links to cold weather-related Lessons Learned reports.

Stakeholders have until Sept. 21 to comment on the changes.

NERC also previewed this year’s Winter Reliability Assessment during the webinar, though it did not have much new to report.

Reliability Assessment Engineer Stephen Coterillo said preliminary data indicate capacity resources will be adequate. Most NERC assessment areas’ reserve margins should be well above their reference levels, with only Manitoba and the Maritimes just barely under them.

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NEPOOL Markets Committee Briefs: Sept. 8, 2020

The New England Power Pool Markets Committee began a three-day meeting Tuesday at which stakeholders will discuss updated parameters for Forward Capacity Auction 16 for 2025/26.

Before those discussions, members heard an update on ISO-NE’s next FERC Order 841 compliance filing and its proposal to sunset the Forward Reserve Market (FRM).

Order 841 Compliance Update

ISO-NE’s Jennifer Wolfson gave the committee a presentation on the RTO’s plans for responding to FERC’s Aug. 4 order on its second Order 841 compliance filing. (See FERC OKs Most of ISO-NE 2nd Storage Compliance.)

One set of changes responds to FERC’s concern that the RTO’s Tariff language preventing double payment for charging energy at the retail and wholesale levels could allow host utilities to decide whether an electric storage resource (ESR) may participate in its markets. The changes would be effective in the first quarter of 2021.

The other changes address FERC’s directive that ISO-NE add to its Tariff the mechanism by which it will account for state of charge and duration characteristics in the day-ahead energy market. The RTO will propose four day-ahead bidding parameters: initial state of charge; maximum state of charge; minimum state of charge; and round-trip efficiency. They would be effective Jan. 1, 2026.

The RTO also will propose several clean-up revisions to Appendix C of the Tariff.

ISO-NE has asked FERC to allow it to make the filing by Dec. 7. It is targeting a vote by the MC in November and will seek Participants Committee endorsement in December.

NEPOOL
Green Mountain Power’s Stafford Hill Solar Farm in Rutland, Vt., was the first in the region to use battery storage to reduce peak demand. | UVM

The commission’s August order also rejected language applying transmission charges to an ESR when that resource is charging for later resale in wholesale markets and is not providing a service, and to include a basic description of ISO-NE’s metering methodology and accounting practices for ESRs.

The commission also disagreed with the RTO’s contention that storage resources will always be providing a service when charging for later resale in the wholesale markets and should thus be exempt from transmission charges. It said ISO-NE should account for self-scheduled megawatts when calculating an ESR’s contribution to regional network load.

The RTO’s response on the transmission charge exemption will be discussed at the Transmission Committee and Participating Transmission Owners Administrative Committee.

Forward Reserve Market Sunset

The committee also heard a presentation on the RTO’s proposal to sunset the FRM on June 1, 2025, to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative. (See “ISO-NE Seeks to Sunset Forward Reserve Market,” NEPOOL Markets Committee Briefs: Aug. 11-13, 2020.)

The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves.

Transmission investments and market changes, including the anticipated implementation of ESI, have or will relieve many locational constraints and reward resource flexibility, the RTO says, making the FRM unnecessary.

ISO-NE plans an MC vote on the proposal in October, followed by a PC vote in November and a FERC filing by the end of the year.

The RTO’s Jonathan Lowell presented two versions of the proposed Tariff language because of uncertainty over when FERC will rule on the ESI proposal, which was filed in April. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

One version would be filed if an order on ESI is received by the end of the year that accepts the parts of the initiative that would supplant the FRM — specifically, provisions regarding 10- and 30-minute reserves in the day-ahead market.

Another version includes “contingency language” in case FERC does not act by the end of the year.

If the commission issues an order before the end of the year but rejects the ESI reserves provisions, no sunset filing would be made until the RTO wins approval of a market design that includes day-ahead reserves.

Lowell responded to a stakeholder question about why the RTO wouldn’t sunset the FRM for FCA 15 to avoid an ESI/FRM overlap.

Lowell said bidders have already made decisions for FCA 15 based on the net cost of new entry and other parameters already set for the auction.

“Setting the FRM sunset to align with [capacity commitment period] 15 at this point in time is not a feasible course of action,” the RTO said.

Generation Information System Referral

The committee approved the referral to the NEPOOL Generation Information System (GIS) Operating Rules Working Group of requests to improve uploads by independent verifiers and enable application programming interface (API) access to the account holder public report. The GIS issues and tracks certificates for all generation and load produced in the ISO-NE control area as well as imports.

PowerDash, which provides software for the management and monitoring of alternative energy installations, asked the GIS Usability Group to address a problem with the uploads of “independent verifiers” — third-party meter readers.

Currently, if a facility that has not been assigned a “verifier” status is included in a comma-separated value (CSV) upload by a third-party meter reader, the entire upload fails. The proposed change would provide an error message indicating that the facility is not present in the account but would allow all other data to be uploaded. PowerDash said the change would reduce the need for manual crosschecks between the GIS account holders’ internal systems and the GIS.

The Usability Group also received a request from SRECTrade, which provides transaction and management services for solar renewable energy credits, to enable API access to the account holder public report. Currently, the API requires an account ID for each account to which the user is delivering certificates.