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October 15, 2019March 13, 2025

IBR Guideline Seeks to Address ‘Tweener’ Interconnections

By Rich Heidorn Jr.

In the first 16 months after its creation in 2017, NERC’s Inverter-Based Resource Performance Task Force produced four disturbance reports, two alerts, several webinars and a reliability guideline. Its latest creation could be considered its Greatest Hits.

“I refer to it as a comprehensive guide for all things inverters,” NERC’s Rich Bauer said during a webinar Friday on the new publication, Improvements to Interconnection Requirements for BPS-Connected Inverter-Based Resources.

The task force began disseminating a 98-page inverter performance guideline a little over a year ago.

“Our recommendation to transmission owners is you need to be familiar with the guideline and incorporate what’s in [it] in your interconnection requirements,” Bauer said. “We got a lot of feedback from the industry, and they said, ‘What are the critical pieces in the performance guideline that we should include in our interconnection agreements?’ That’s really what spawned this latest guideline.”

Although many of the task force’s recommendations apply to balancing authorities, reliability coordinators or transmission operators, they are generally addressed to the TO, which is responsible for maintaining interconnection requirements under reliability standard FAC-001 and for conducting interconnection studies under FAC-002.

The new 52-page publication seeks to cover the growing number of inverter-based generator interconnections that fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV) that is subject to NERC’s standards. The task force says “the vast majority of solar PV plants connected to the BPS [bulk power system], totaling over half the capacity, are not considered BES and are therefore not subject to NERC reliability standards.”

“Maybe it’s connected at less than 100 kV, but it’s more than 75 MVA. Maybe it connects at 69 or 92 kV. Or maybe it connects at greater than 100 kV, but it’s less than 75 MVA. Those are [what] I call the ‘tweener’ interconnections,” said Bauer, NERC’s associate director of reliability risk management.

“While each individual resource may not have a substantial impact to the BES, the overall response, behavior and control of these resources impact BPS reliability and stability,” the guideline says. “It is therefore critical to have consistency across the generating fleet.”

A growing number of inverter-based generator interconnections fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV). | NERC Inverter-Based Resource Performance Task Force

If widely adopted, the guideline could act as a de facto standard. Although interconnections outside the BES definition are not directly subject to NERC standards, the task force realized it could still influence them indirectly: The guideline includes 18 recommendations for interconnection requirements and six for modeling.

The task force said the guidelines will serve as a “bridge” to the Institute of Electrical and Electronics Engineers’ P2800 effort to standardize the performance and capability of newly interconnecting BPS-connected inverter-based resources (IBRs). Completing the standard and getting it adopted by relevant authorities is expected to take about two years.

“A significant portion of [the 2018 performance guideline] looks a lot like an equipment specification, and NERC standards [have] never really delved into the area of providing equipment specifications,” Bauer said. “We recognized this fairly early on and … that’s what spawned this IEEE 2800 project.”

Unlike a NERC standard, which would cover legacy equipment, the new guideline is intended to apply only to new and “materially modified” interconnections involving IBRs. IBRs are not “brand-new” to the bulk system, said NERC’s Ryan Quint, citing wind farms installed since the 1980s.

The majority of solar PV resources are connected at voltage levels less than 100 kV and are sized at less than 75 MW in capacity, making them exempt from NERC reliability standards. | NERC Inverter-Based Resource Performance Task Force

“There is a lot of legacy equipment out there. Not all of that the legacy equipment can meet the recommended performance that we’re seeking today,” said Quint, senior manager of advanced analytics and modeling.

Grid operators need more granular data because of the growing penetration of IBRs, he said.

“Clarity and consistency [are] needed for inverter-based resources because their electrical response and behavior when they’re connected to the grid is dominated by controls rather than physics,” Quint said. “The inverters, the plant-level controllers, the communication — all the stuff that interacts to make the plant behave the way it does — is all based on a control system … that can be [programmed] to some extent to meet certain performance requirements and ensure reliability of the grid. … The goal is not to have expensive, overbearing requirements for inverter-based resources. It’s just to bring clarity to what the grid really needs.”

Monitoring

In producing reports on the August 2016 Blue Cut Fire, the October 2017 Canyon 2 fire, and the 2018 Angeles Forest and Palmdale Roost disturbances, the task force discovered that some of the IBR facilities “lacked the data we really needed to analyze those events in great detail,” Bauer said.

He said investigators need high-resolution, time-synchronized data. “We actually recommend where we would take measurements at. Of course, we would want a measurement at the point of interconnection, but there’s also a really big need to see data down in the plant … down at the individual inverter level.”

Weak Grid

Bauer said a recent incident in the U.K. has highlighted the need to understand how inverters affect the grid’s short-circuit strength.

The U.K. grid lost 800 MW of generation, shedding load to 1 million customers, after the voltage-regulating control on a very large wind facility became unstable.

“Make sure you study all potential configurations on your system to ensure that you can’t end up in a weak grid situation, because that’s in essence what happened in the U.K.,” Bauer said. “They had some planned maintenance outages, which put them in a weak grid situation … and that’s what caused their control to go unstable.”

“Weak grid” concerns are on the mind of engineers in New England, ISO-NE associate engineer Brad Marszalkowski said. “Lately we’ve been doing [electromagnetic transient modeling] for every interconnection request because they’re all inverter-based resources,” he told the webinar. “We see a lot of these weak grid issues.”

Be Proactive

Jeff Billo, ERCOT’s senior manager of transmission planning and the task force’s vice chair, also offered some lessons learned during the webinar.

ERCOT, which has 22 GW of wind and almost 2 GW of utility-scale solar, could add another 10 GW of wind and about 4 GW of solar in the next 15 months, if all the signed interconnection agreements backed with financial security postings come to fruition.

The Texas grid operator recently created a new task force in response to interconnection requests for “multi-hundred-megawatt” batteries, Billo said. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)

Billo cited Texas’ IBR growth “to emphasize how important the work is at IRPTF to ERCOT and why we’re taking this as seriously as we are.”

ERCOT has banned IBRs from using momentary cessation since 2015, he said. “However, we were surprised when we got the survey responses back from the second NERC alert last year. There were some of the newer solar resources that were using that momentary cessation. We’ve identified that we need to clarify our requirements.

“We don’t want to wait until we start seeing problems on our grid before we start to implement some of these requirements,” he continued. “We’ve found it’s really important to be proactive in getting the requirements out, because once you have a problem on your system, it’s really too late. It’s near impossible to go back and retrofit the equipment that’s already in the field.”

October 15, 2019

CPUC Orders Changes to PG&E Shutoff Rules

By Robert Mullin

California officials on Monday continued to heap criticism on Pacific Gas and Electric for initiating a massive blackout across much of its territory last week, with the state’s top regulator ordering “immediate corrective actions” to the company’s policies and Gov. Gavin Newsom calling for refunds to the 738,000 customers affected.

In a letter to PG&E CEO Bill Johnson, California Public Utilities Commission President Marybel Batjer condemned the utility for “failures in execution” during the largest public safety power shutoff (PSPS) in the state’s history, while directing the company’s top executives and board members to attend an emergency meeting Friday to share what they learned from the controversial shutoff and how they plan avoid a repeat.

“It is critical that PG&E, along with all the other utilities in the state, learn from this event and take steps now to ensure mistakes and operational gaps are not repeated,” Batjer said.

Batjer’s letter followed her harsh comments during last week’s CPUC voting meeting, saying PG&E’s “absolutely unacceptable” measures cannot become the “new normal” for the state. (See PG&E Restores Po w er amid Backlash.)

PG&E shutoff rules — PG&E has said it recorded about 50 instances of damage to its equipment in areas affected by last week’s PSPS, including these downed lines in Shasta County. | *PG&E*

The tone of the Oct. 14 letter was more conciliatory, with Batjer commending the cooperation and transparency of PG&E staff who “worked to overcome challenges” during the event. But she also called out PG&E on several shortcomings, including its failure to heed recommendations from state and local agencies, which contributed to a critical breakdown of public communication and coordination. Those recommendations included establishing a communication structure that allows emergency personnel to receive information outside general updates to local governments, developing lists of critical facilities with county and tribal governments, identifying critical fuel-supply needs and coordinating with local governments to select PSPS-specific community resource centers.

Batjer pointed to the performance of PG&E’s website — a “cornerstone” of the company’s public information effort, which crashed within 24 hours of the PSPS declaration. That left PG&E staff struggling “to provide necessary information to their customers, the public and frontline safety officials with affected state, county and tribal governments.”

Batjer also faulted PG&E for failing to scale its operations to meet the increased customer inquiries precipitated by the event. In response, she ordered the company to identify the maximum outage that could occur during a PSPS and ensure “commensurate bandwidth requirements” for web and call services to be available at all times.

Other corrective actions required by the CPUC include:

Accelerating the restoration of power, with a goal of less than 12 hours — similar to the requirement after major storms;
Taking steps to minimize the magnitude of future PSPS events;
Establishing a more effective communication structure with county and tribal government emergency management personnel;
Improving processes and systems for distributing maps to counties and tribal governments showing the boundaries of the most recent PSPS-affected areas;
Developing a list of existing and possible future agreements for on-call resources that can be called upon in an emergency;
Ensuring PG&E personnel involved in PSPS response in emergency operations centers are trained in California’s Standardized Emergency Management System.

‘Right Decision’

In a letter to Batjer Monday, Gov. Newsom laude d the CPUC for its “swift response” to his request for an immediate “comprehensive inquiry” into the PG&E’s blackout event.

But a separate let t er to PG&E Corp. CEO Bill Johnson had sharper words, with the governor castigating the company over the “unacceptable scope and duration” of the outages, which he said were “the direct result of PG&E prioritizing profit over public safety, mismanagement, inadequate investment in fire safety and fire prevention measures and neglect of critical infrastructure.”

Newsom also echoed Batjer’s criticism of PG&E for its failure to heed the recommendations of public agencies in executing its PSPS measures.

“PG&E’s lack of preparation and poor performance is particularly alarming given that, prior to the event, top executives responded to the scrutiny and questioning of state and local agencies by asserting that PG&E could handle a public safety power shutoff event,” Newsom wrote. “And PG&E turned down recommendations and offers of assistance from public agencies that are experts in crisis management, including the Governor’s Office of Emergency Services [OES].”

Newsom urged Johnson to have PG&E refund $100 to each residential customer affected by the blackout and $250 to each small business customer.

“This refund should be funded by shareholders, not ratepayers,” Newsom said.

Johnson defended PG&E’s actions, saying the company “closely” coordinated its activities with the CPUC, OES and the California Department of Forestry and Fire Protection before and during the event.

“Representatives from those agencies were embedded in our Emergency Operations Center and we welcomed and accepted their help and counsel, and PG&E employees were also embedded at Cal OES in Sacramento,” Johnson said in a state m ent. “We also worked closely with county and local officials throughout the PSPS.”

But he also acknowledged there were “areas” where PG&E “fell short of its commitment to serving our customers during this unprecedented event,” specifically in its customer communications.

Still, Johnson pointed to what he considered a key — and positive — outcome of the PSPS: that no fires were sparked in PG&E’s territory. The company has sa i d it recorded about 50 instances of weather-related damage to its equipment in PSPS-impacted areas, including downed lines and vegetation making contact with wires.

“We appreciate the significant impact that turning off power for safety has on our customers and the state. While we recognize this was a hardship for millions of people throughout Northern and Central California, we made that decision to keep customers and communities safe,” Johnson said. “That was the right decision.”

October 13, 2019February 18, 2025

Transmission Developer Calls for Closer Look at NorthernGrid

By Robert Mullin

A proposed merger of two Northwest transmission planning groups has won the endorsement of state regulators, but a prominent independent transmission developer is calling on FERC to convene a technical conference to scrutinize the effort before signing off.

In a limited protest submitted to FERC on Oct. 7, LS Power says it agrees in principle with the consolidation of ColumbiaGrid and Northern Tier Transmission Group (NTTG) into a single regional planning organization (RPO) called NorthernGrid (ER19-2760, et al.). But the company also questioned whether the new entity will be any more successful than its predecessors at producing the kind of regional transmission projects envisioned by the commission’s Order 1000.

In that landmark 2011 order, FERC mandated that transmission providers participate in processes that produce a regional transmission plan and amend their tariffs to include procedures for public policy requirements. The order also sought to open projects identified in those regional plans to competition by non-incumbent transmission developers.

“To date, neither ColumbiaGrid nor NTTG have selected a single regional solution to transmission needs identified in the respective planning processes by individual transmission owners,” LS Power wrote in its filing. “While LS Power is generally supportive of the endeavor to combine the two regions, it also believes that this is an opportunity to establish a transmission planning region that engages in meaningful regional planning that leads to the identification of more efficient and cost-effective transmission solutions rather than simply rolling up local transmission plans.”

If approved by the commission, NorthernGrid’s planning territory would encompass parts of California, Idaho, Oregon, Montana, Nevada, Washington, Wyoming and the entire state of Utah. Members would include ColumbiaGrid’s Avista, Bonneville Power Administration, Chelan Public Utility District, Puget Sound Energy, Seattle City Light and Snohomish Public Utility District, along with NTTG’s Deseret Power, Idaho Power, Enbridge, NorthWestern Energy, PacifiCorp, Portland General Electric and Utah Associated Municipal Power Systems.

In line with current practice, BPA and the publicly owned utilities — all non-jurisdictional to FERC — would be considered “non-enrolled” members in the new RPO. The RPO would coordinate their planning with their investor-owned neighbors, but they would not be subject to federal authority or Order 1000.

A Plan for Planning

The proposed merger is the result of a four-year effort to replace ColumbiaGrid and NTTG, the proponents noted in their Sept. 6 filings, which requested FERC approve the new RPO effective Jan. 1, 2020.

They said the merger will allow for “collaborative” regional planning on a single timeline, reduce member expenses through broader sharing of administrative expenses and reduce the interregional coordination requirements for all Western RPOs by eliminating one region. Membership would be open to any entity that owns or operates transmission facilities in the Western Interconnection, is electrically connected to an existing member or proposes to build a project making such a connection.

NorthernGrid regional transmission planning area - that LS Power wants to ensure is open to competitive transmission

The new NorthernGrid regional planning organization would consolidate the areas currently covered by ColumbiaGrid and Northern Tier Transmission Group. | ColumbiaGrid

NorthernGrid would follow a two-year transmission planning cycle. The process would kick off with a gathering of input on study scope, including local transmission plans, new proposed projects (including Order 1000 candidates) and public policy requirements. Later during the first year, the RPO would develop the study scope and methodology and perform technical analysis and coordination with other regions. It would complete the year by issuing a draft regional plan.

Year 2 of the cycle would start with a review of the draft plan and an update of data points, followed by an update of the regional study scope and development of cost allocation solutions. The process would wrap up later that year with a review of the final regional plan, allocation of cost responsibility for regional projects and plan approval.

‘Fundamental Issues’

LS Power contends that NorthernGrid’s planning process “raises fundamental issues about how the planning process should be structured,” pointing out that the proposed process largely draws from existing processes used by ColumbiaGrid and NTTG — one the company said has been unsuccessful for independent developers.

“To properly evaluate whether the new NorthernGrid proposal will meet the commission’s goals, the commission must look at whether the previously approved ColumbiaGrid and NTTG processes effectively met those goals,” the company said. “Although those proposals were approved as compliant with Order No. 1000, the proponents now have at least five years of data available to test the effectiveness of the regional planning.”

LS Power offered its own verdict: “To date, neither ColumbiaGrid nor NTTG have authorized a competitively determined transmission addition under their Order No. 1000 process.”

The company also contends that “aspects of the proposal show that the planning process favors local transmission planning.” It asked FERC to require NorthernGrid to engage in transmission planning that leads to the evaluation of projects that may be more efficient or cost-effective than local solutions.

LS Power said FERC should consider imposing additional requirements on NorthernGrid, including:

giving developers and other stakeholders an opportunity to propose regional needs and solutions after NorthernGrid has finalized the study scope;
clarifying when the region will determine whether a project proposed for regional cost allocation is a more efficient or cost-effective solution than a local project;
revising the non-enrolled developer agreement to allow a developer to seek resolution at FERC through a complaint under Section 206 of the Federal Power Act;
altering the governance structure to allow stakeholders to vote and ensure greater independence from incumbent transmission providers; and
developing a pro forma agreement laying out the rights and obligations of a developer whose regional project is selected by the RPO.

LS Power also said the filing is deficient because NorthernGrid did not include a copy of its planning agreement with the non-enrolled members, such as BPA, whose transmission facilities “interconnect or are intertwined” with the systems of the RPO’s “enrolled” members.

“The NorthernGrid filers intend to coordinate planning with non-enrolled nonpublic utility transmission providers. To that end, they developed a separate planning agreement that is substantially similar to the planning that occurs within Attachment K [of a transmission provider’s tariff], but excludes the cost allocation provisions,’” LS Power said.

The company argues that FERC should hold a technical conference to evaluate how well ColumbiaGrid and NTTG have identified projects that solved their regions’ needs “and, if those entities were not successful in identifying regional projects, whether that is due to flaws in the planning process that should be corrected so that the flaws will not carry over to the new (and combined) NorthernGrid.”

“The commission should not accept the new Attachment K until these issues are better fleshed out. Commission precedent shows that a technical conference is good vehicle for fleshing out issues of this type,” the company said.

Proposal Addresses ‘Key Concern’ for States

The NorthernGrid proposal has earned the backing of a key constituency: state utility commissioners, who applauded the group for providing states with a “meaningful role” in planning through the appointment of two representatives from each state on an Enrolled Parties and States Committee.

“There, state entities and jurisdictional members may collaborate to form perspectives on the study scope and plan that the committee’s co-chairs will carry forward to the NorthernGrid planning committee,” commissioners from Idaho, Oregon, Washington and Wyoming wrote in joint comments filed with FERC.

The role of states in NorthernGrid had been a “key concern” for regulators because ColumbiaGrid had “no formal role for states distinct from other stakeholders,” while utility regulators do have formal roles on NTTG’s Steering Committee, they said.

The commissioners said they “appreciate the willingness of the NorthernGrid entities to work toward a solution that recognizes the important role of states and accommodates many state priorities, even within a complex organizational structure.” They pointed out that the footprints of the two planning regions already represent “an interconnected region with significant overlap” in customers, generation and transmission. Their combination “will better reflect the scope of the regional benefits of transmission solutions being evaluated, as well as produce administrative cost efficiencies that benefit customers across the region,” they said.

LS Power wants to ensure all transmission development allows competitive bidding.

BPA line in The Dalles, Ore. | © RTO Insider

They also contend that the “best regional solutions” will depend on investor-owned utilities collaborating with BPA and the region’s publicly owned utilities.

“Navigating the legal and administrative complexity of an organizational structure that accommodates both Order 1000 entities and non-jurisdictional entities is difficult but necessary to achieve broad regional collaboration,” they wrote.

The commissioners acknowledged that their concerns were centered on NorthernGrid’s governance and that FERC must deal with many other organizational details in its review process. “Although we do not intend to take positions on any other issues that may arise, we do encourage FERC to evaluate the filing as expeditiously as possible, so that transition to the new organization can align efficiently with the beginning of the next two-year planning cycle,” they concluded.

October 13, 2019

MISO Market Subcommittee Briefs: Oct. 10, 2019

CARMEL, Ind. — MISO is planning a spring filing with FERC to implement a payment structure for resources that re-energize islanded areas of the grid following a blackout.

“It’s interesting to stand up here and talk about something that we hope never happens. But we do see value in having a process,” Director of Settlements Laura Rauch told stakeholders at Thursday’s meeting of the Market Subcommittee.

Laura Rauch at the MISO Market Subcommittee meeting — Laura Rauch, MISO | © *RTO Insider*

MISO’s preliminary proposal stipulates that, as a starting point for pricing, compensation for restoration energy will rely on resources’ last submitted offers before an emergency strikes, resulting in unique costs based on each resource rather than a uniform clearing price. The RTO will allow for recovery of start-up costs, emergency purchases and resource-specific energy costs. It will also include recovery for any unusual costs incurred during operation, provided they can be verified by the Independent Market Monitor. The RTO will also accept after-the-fact updates of offers.

Restoration pricing differs from MISO’s existing black start services definition because black start resources derive their revenues from the capacity they provide, not the energy market.

Rauch said restoration events will be considered over when the day-ahead market once again takes over economic dispatch of resources in the islanded area.

“We’ll need to define the area of impact and the island,” she added.

Rauch said MISO realizes load and generation totals during a restoration event “may be imbalanced” but said total generation costs will be allocated on a load-ratio share. The RTO had originally considered allocating resource costs based on local balancing authority boundaries, but this summer it said load ratio would be simpler to implement.

RTO officials have also said a fixed-price compensation approach for restoration energy would be a blunt instrument that would at times result in under- or over-collection by generators.

“The downside is that it’s much more complex,” MISO Director of Market Services John Weissenborn said in June of a unit-by-unit pricing calculation and settlement based on offers.

MISO Preps Tariff for Short-term Reserves

Although MISO filed with FERC on Oct. 4 to include a short-term reserve product definition in its Tariff (ER20-42), stakeholders shouldn’t expect generators to fire up to furnish the reserves until late 2021.

The RTO asked that the commission act on its request by Jan. 31 but make the revisions effective Dec. 7, 2021, seeking a waiver of FERC’s 120-day maximum notice requirement to give its Monitor and stakeholders “adequate time to budget for in advance and develop and test significant software and other operational adjustments.”

MISO said it’s already begun working with tentative market platform replacement vendor General Electric on software design details.

The reserves are meant to supply energy within 30 minutes to meet reliability needs and reduce make-whole payments, and MISO expects them to be especially useful in portions of MISO South, where the RTO’s subregional transmission limit restricts imports.

MISO expects the short-term reserves product to clear $4 million in revenue annually when it goes live in 2021. It also estimates an approximate $5 million annual net production benefit when the reserves are used. Part of the savings will result from RTO operators taking fewer out-of-market actions, for which it must make revenue sufficiency guarantee payments. (See “Short-term Reserves,” Stakeholders Confused over MISO Roadmap.)

— Amanda Durish Cook

October 13, 2019

MISO Files Offer Cap Revisions Ahead of Schedule

By Amanda Durish Cook

CARMEL, Ind. — MISO is hoping to avoid the need for a sixth straight waiver of its $1,000/MWh offer cap this winter, filing a year ahead of a FERC deadline to double its hard cap.

The RTO on Oct. 1 filed for the third time a proposal to adopt a $1,000/MWh soft cap and a $2,000/MWh hard cap on energy offers — and make corresponding changes to its demand curves (ER2 0 -11).

MISO had until Oct. 1, 2020, to implement a $2,000/MWh hard cap for verified cost-based incremental energy offers after FERC last year said its plan still needed a few tweaks. While the commission accepted much of MISO’s plan to permanently double its hard offer cap, it also required the RTO to pledge to apply the new hard cap to adjusted energy offers from fast-start resources. (See FERC OKs MISO’s Doubled Offer Cap, Orders Alterations.) The new filing is considered a “true-up” filing rather than a compliance filing, the RTO said.

MISO plans to go live with the new offer cap by Dec. 1, having completed “two or three back-and-forths with FERC,” Senior Market Engineer Chuck Hansen said at Thursday’s Market Subcommittee meeting.

Executive Director of Market Operations Shawn McFarlane said he hoped the filing would supplant the need to request a sixth waiver of its $1,000/MWh offer cap this winter. (See MISO Gets 5th Winter Waiver of Offer Cap.)

Hansen said MISO was able finish its offer cap work ahead of deadline because it and market platform vendor General Electric found themselves with more time while they await a FERC order on the RTO’s plan to incorporate energy storage resources into its markets. MISO originally asked for an order on energy storage compliance by July 1 while anticipating “significant” software work thereafter on a storage participation model.

Hansen also said additional staff time was freed up because FERC has yet to issue a final rule for RTOs to craft a participation model for distributed energy resources.

Hansen said MISO will only seek a sixth waiver if FERC rejects the filing. That waiver would closely resemble the last five it filed, he said, with verified energy costs above $1,000/MWh recovered via revenue sufficiency guarantee payments.

MISO’s offer cap plan specifies that all resources, regardless of type, are eligible to submit cost-based energy offers above $1,000/MWh. This time, it added that fast-start resources will not be able to set prices above the $1,000/MWh soft cap or above the $2,000/MWh hard cap without offers first being verified or mitigated by the Independent Market Monitor.

Along with the higher caps, MISO has added a $2,100/MWh prolonged step to its operating reserve demand curve (ORDC) so that resources will receive nearly double the energy price when supply is scarce.

The ORDC will begin at $3,300/MWh, dropping to $2,100/MWh for much of the curve when the RTO clears 8% of its requirement level. At 89%, the level falls to MISO’s original $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.

MISO is planning to maintain its $3,500/MWh cap on the value of lost load (VoLL) over the Monitor’s longstanding criticism that VoLL could be pushed as high as $12,000/MWh to create a more sloped contingency reserve demand curve.

Hansen said MISO still plans to work with stakeholders in the coming months to recast VoLL limits.

October 11, 2019

Calif. Regulators Bash PG&E’s Power Shutoffs

By Hudson Sangree

As roughly 600,000 Pacific Gas and Electric customers remained without power Thursday, the president of the California Public Utilities Commission called the situation “unacceptable.”

“The management and the response of the company, PG&E, to the [public safety power shutoffs] have been absolutely unacceptable,” CPUC President Marybel Batjer said during a commission meeting in San Francisco. “The impacts to individual communities, to individual people, to the commerce of our state, to the safety of our people has been less than exemplary.

PG&E California Regulators — CPUC President Marybel Batjer | *State of California*

“This cannot be the new normal,” Batjer said. “We can’t accept it as the new normal, and we won’t.”

She called for a review of the public policies that led to the largest blackout to prevent wildfires ever to hit the state.

Earlier this week, PG&E said it might de-energize lines serving roughly 800,000 customers — or approximately 2.4 million residents — in 34 counties of northern and central California. The utility shutoff power to 513,000 customers starting early Wednesday morning and 234,000 more on Thursday. (See Judge Admits PG&E Takeover Plan as Utility Blacks Out Millions.)

At the same time, it restored power to 126,000 customers, including many along California’s North Coast, as the gusting winds that prompted the outage subsided in some areas but picked up in others.

Following procedures established by the State Legislature and the CPUC in recent years, PG&E was trying to prevent fires sparked by electrical equipment in its service territory like those of October 2017 and November 2018, which killed at least 125 people and destroyed nearly 26,000 structures during similar dry, windy conditions.

“We faced a choice between hardship or safety, and we chose safety,” Michael Lewis, PG&E’s vice president of electric operations, said in a statement. “We deeply apologize for the inconvenience and the hardship, but we stand by the decision because the safety of our customers and communities must come first.”

Eighty-six people died in the Camp Fire of November 2018, which destroyed the town of Paradise and leveled more than 14,000 homes there, making it by far the deadliest and most destructive fire in state history. PG&E has acknowledged its equipment likely started the fire beneath a 100-year-old transmission line, which critics contend was poorly maintained. (See Cal Fire Pins Deadly Camp Fire on PG&E.)

Commissioner Genevieve Shiroma suggested this week’s massive shutoff wouldn’t have been necessary if PG&E had maintained and upgraded its infrastructure to prevent fires.

“The sheer magnitude [of PG&E’s public safety power shutoff] is indicative of the condition of the utility in terms of what we call the hardening — that means the condition of the poles, the lines, the wires, the transformers, the transmission lines — and the maintenance, or lack thereof, of the system and the vegetation management,” Shiroma said.

PG&E also came under fire at the CPUC meeting and elsewhere for the failure of its website to handle the crush of traffic from residents seeking information this week. State employees had tried to help PG&E address its website and server issues, the CPUC’s deputy executive director for safety, Elizaveta Malashenko, told commissioners.

Malashenko said the shutoffs affected about 2,400 miles of transmission lines and 24,000 miles of distribution lines. CAISO Seeking to Contain PSPS Spillover.)

Winds are expected to die down by Friday, Malashenko said. PG&E has 45 helicopters and 6,000 personnel assigned to restore power, but crews must visually inspect all lines before re-energizing them, meaning the work could take days, she said.

Southern California Edison shut off power to about 13,000 customers on Thursday at noon as wildfires flared and Santa Ana winds blew hot and dry in Los Angeles, San Bernardino and Ventura counties. It had plans in place to blackout up to 174,000 residents as of early Thursday morning.

San Diego Gas & Electric has also warned of possible shutoffs.

October 11, 2019

MISO RASC Briefs: Oct. 9, 2019

CARMEL, Ind. — MISO says it will wait another year before moving to tighten deliverability requirements in its capacity auctions, a decision that has irked stakeholders who say guaranteed deliverability to load is too essential to put on hold.

MISO’s Independent Market Monitor has argued that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, MISO allows resources to demonstrate deliverability only up to the unforced capacity levels, which tend to be about 5 to 10% below full ICAP levels.

The Monitor has said MISO should require deliverability for all capacity resources based on full ICAP, after finding that one unit came up short by “tens of megawatts” in the 2016 Planning Resource Auction.

MISO Resource Adequacy Subcommittee — Darrin Landstrom, MISO | © *RTO Insider*

The RTO has so far developed possible solutions only for intermittent resources, citing the increasing number of wind curtailments in the footprint. It noted that curtailments rose to an all-time high of nearly 5 GW in May — although multiple stakeholders said it is missing key context on when such curtailments occur, arguing that curtailment at peak demand is very different from curtailment at 3 a.m.

At a Resource Adequacy Subcommittee meeting Wednesday, MISO adviser Darrin Landstrom said the RTO plans to estimate the average capacity factor for intermittent resources based on their transmission service request values, which will possibly reduce capacity credits.

The solution is one of three options MISO shopped in August to address the issue. (See MISO Deliverability Plan Prompts Skepticism.)

But that solution wouldn’t apply to the capacity auction until the 2021/22 planning year, staff said. Landstrom said MISO would likely be unable to make a filing before the end of the year.

“I really don’t think it’s acceptable that MISO will delay a solution another calendar year,” Gabel Associates’ Travis Stewart said, urging staff to come up with a temporary solution in time for the 2020/21 planning year.

MISO has acknowledged that the Monitor might dispute capacity auction rights if the deliverability gap causes a “significant” change in clearing prices.

IMM staffer Michael Chiasson said MISO does not need to make a FERC filing to apply stricter deliverability requirements for conventional generation; it need only change its Business Practices Manuals.

But RASC liaison Patrick Brown said capacity resources need time to react to the change. He also said the RTO needs a year to make complex software changes to accommodate new deliverability requirements.

Complaint over Extended Outage Rule Change

MISO is sticking with a less aggressive plan designed to dissuade capacity resources from taking long outages that could risk supply and plans to submit a FERC filing later this month.

The provisional change would limit extended planned outages to a cumulative 90 days of the first 120 days of the planning year — June 1 to Sept. 30 — which MISO deems the most critical months in terms of demand. Resources that are unavailable for more than 90 days during the first four months of the planning year would be disqualified from auction participation. (See MISO Eases New Rules on Extended Outages.)

Tim Bachus, MISO’s capacity market administration analyst, said the temporary change is only meant for the 2020/21 planning year auction. He said he’s heard criticism that the proposal is too lenient, with some stakeholders asking instead for a 30-day outage limit.

“This is really a short-term fix … one, maybe two years total,” Bachus said. “We just want to address resources that take capacity payments but aren’t available at the most critical times.”

The short-term proposal might tackle Wolverine Power Supply Cooperative’s late September complaint with FERC over MISO allowing a yearlong planned outage of a large resource in Michigan in the 2019/20 auction (EL19-102). The RTO currently issues no penalties for capacity resources that take extended outages.

The co-op said MISO’s Tariff flaw “was exposed most recently by the results of the 2019/2020 PRA that created a capacity shortfall in Michigan’s Lower Peninsula; yielded objectively unjust and unreasonable clearing prices well below the prices that would motivate new investment or keep older existing units in operation; and ensured that market participants were inadequately compensated for their actual capacity contributions.” Wolverine argued it’s not fair to consumers and market participants that MISO allows resources to set clearing prices even when their owners are aware they will be unavailable for the planning year, undercutting market principles and jeopardizes reliability.

New PRA Deadlines Approved

In a brief letter order Oct. 3, FERC gave MISO permission to shift its deadlines for its capacity auctions, allowing market participants more time to prepare data submittals and end the RTO’s practice of opening and closing the offer window in the middle of the night (ER19-2559).

Under the rule changes, demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data will be due at different points in the winter instead of fall. MISO will also open its four-day offer window at 8 a.m. ET and close at 6 p.m. instead of the usual midnight-to-midnight run. (See “New PRA Deadlines Before FERC,” MISO Resource Adequacy Subcomm . Briefs: Sept. 12, 2019.)

The new deadlines will take effect beginning with the 2020/21 PRA. Some planning resource performance data, including generation verification test capacity, is due Oct. 31. Load-serving entities must submit their peak demand forecasts for the upcoming planning year by Nov. 1, the same date that MISO will publish the results of its annual LOLE study.

— Amanda Durish Cook

October 11, 2019

Report: PJM’s Summer Operations ‘Uneventful’

By Christen Smith

PJM’s grid coasted through an “uneventful” summer highlighted by a new record for weekend peak load and the lowest forced outrage rate in five years — the result of evolving resources and system planning, the RTO said in a re p ort published Wednesday.

“The system would not have handled these high demands as smoothly a decade ago,” said Kevin Hatch, a supervisor in PJM’s dispatch system operations. “We are seeing generators that are increasingly responsive to our operational requests, a transmission system that is more robust, and the benefits of efficient and reliable resources through the capacity market.”

Summer demand peaked at 151,558 MW on July 19 in the midst of a hot weather alert — one of 13 called in the region during the season, which spanned June 1 through Sept. 15. The following day, the grid set a new weekend peak load record of 149,751 MW. The average LMP hovered around $25/MWh, with prices during the daily peak spiking to $45/MWh.

Although “relatively” mild weather enhanced the grid’s smooth performance, the report emphasizes the “excellent coordination and cooperation” of PJM members, including responsiveness to dispatch operations, system upgrades and the influx of more efficient generators via the capacity market. These newer resources have replaced aging equipment, driving forced outage rates below 3% this summer, the RTO said.

“We appreciate the cooperation and coordination with our member utility companies,” said Mike Bryson, PJM’s senior vice president of operations. “More efficient generators mean fewer outages, greater reliability and a more efficient system overall.”

PJM summer operations — Average forced outage rate | *PJM*

The report also credited lower fuel prices — combined with the season’s hottest temperatures occurring during periods of lower demand — for keeping LMPs down. Average daily gas and coal prices were 64 cents/MMBtu and 31 cents/MMBtu cheaper, respectively, compared to 2018.

No capacity emergency procedures occurred during the summer. PJM reported three spinning events and 13 hot weather alerts, the fewest recorded in a summer season since 2014. The grid experienced less than 80 post-contingency local load relief warnings, another five-year record low.

Two “notable” gas pipeline events caused temporary disturbances in PJM, according to the report. On Aug. 1, a 30-inch segment of the interstate Texas Eastern Transmission Pipeline in central Kentucky exploded, just a few miles south of a gas-fired generator that serves PJM. The explosion did not harm the unit, and operators isolated the damaged section, saving the grid’s supply of shale gas that flows through the region.

Six weeks later, a compressor station in Northern Virginia on the Dominion Energy Transmission pipeline failed during scheduled maintenance. PJM said a “spell of later summer heat” and the typical generator outage season meant that certain units downstream of the station lost gas supply temporarily. No emergency procedures were issued.

Shoulder Season Surprise

An unexpected hot weather alert on Oct. 2 forced PJM to call upon demand response resources to effectively manage the 126,000 MW peak load.

The RTO declared a pre-emergency load management reduction action just before noon in the American Electric Power, Baltimore Gas and Electric, Dominion and Pepco zones. This directive triggered a performance assessment interval — which measures the production of all resources with Capacity Performance commitments in the affected zones — that lasted approximately two hours.

“We count on our utility partners, generation resources and load management to perform during these tough days, and they did just that,” Rebecca Carroll, PJM’s director of dispatch, said in a statement last week.

Although the event occurred outside the summer season, PJM will address both the report and the DR event at its Operating Committee meeting Tuesday.

October 11, 2019January 15, 2025

SPP Seams Steering Committee Briefs: Oct. 9, 2019

SPP staff told the Seams Steering Committee on Wednesday that MISO is pursuing a number of transmission projects to help it escape from under a settlement agreement that governs the connection between its two regions.

MISO said in July that it is evaluating nine projects to supplement or substitute for the contract path that links its Midwest and South regions over SPP’s system. (See MISO Studying Projects to Cut North-South Tx Reliance.)

“MISO wants to get rid of the settlement agreement — specifically, the $27 million in transmission payments they’re making,” Casey Cathey, SPP’s manager of reliability planning and seams, told the committee during its monthly meeting. “They have a stack of projects they’ve looked at. … They’re being very transparent.”

MISO Midwest and South footprints | MISO

Cathey said MISO intends to fold the projects into its planning efforts, which will be completed by the end of 2020. Similarly, he said, SPP would like to incorporate MISO’s work into its own planning processes and into the RTOs’ next coordinated system plan.

“This is an opportunity for us to have a coordinated plan to meet both MISO and the members’ intentions, but also for SPP to have a portfolio developed that addresses needs along the seam through a series of flowgates that help us to run the market more efficiently,” he said.

Cathey said he would be able to bring more details to the SSC’s December meeting.

Under the terms of a settlement agreement reached in 2015, MISO’s flows on the contract path are capped at 3,000 MW north to south and 2,500 MW in the opposite direction. MISO compensates SPP and six independent transmission owners party to the agreement — Southern Co., Tennessee Valley Authority, Associated Electric Cooperative Inc., Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative — by applying a capacity factor for flows exceeding the previous 1,000-MW contract path in the RTOs’ joint operating agreement.

The settlement agreement expires in January 2021. At that time, the parties can give notice to terminate or revisit the settlement provisions. FERC approved the settlement in 2016. (See FERC OKs MISO-SPP Transmission Settlement.)

RSC-OMS Liaison Group Looks for Answers

Adam McKinnie, an economist with the Missouri Public Service Commission, said SPP and MISO state regulators have gathered initial feedback on the RTOs’ interregional planning processes and will spend the next couple of months evaluating that input.

Commissioners on SPP’s Regional State Committee plan to attend the Organization of MISO States meeting Oct. 24 in New Orleans. The SPP RSC-OMS Liaison Committee will also meet Nov. 17 in San Antonio during the first day of the National Association of Regulatory Utility Commissioners’ annual meeting, McKinnie said.

The Liaison Committee has commissioned an independent analysis to determine whether the RTOs are leaving efficiencies and benefits behind in their interregional planning processes. (See MISO, SPP States Ponder Look at Interregional Planning.)

Stakeholders responded to a request for information in September. Eight of the 14 stakeholders who submitted responses believe an interregional planning analysis will help the committee. Three others suggested additional work on current processes.

Stakeholders have been frustrated by the RTOs’ interregional work, which has yet to result in a joint project.

The commissioners “are looking for information to see what the effects would be from different changes,” McKinnie said. “They didn’t start with a solution. They said, ‘Hey, we need information.’”

The committee has also asked the RTOs’ market monitors to study the grid operators’ markets and operations issues. That work will be delivered by the end of November.

— Tom Kleckner

October 11, 2019

Revised NERC Committee Merger Plan Released

NERC’s Stakeholder Engagement Team (SET) has finalized its proposal to merge the Planning, Operating and Critical Infrastructure Protection committees, setting the stage for expected approval by the Board of Trustees on Nov. 5.

As expected, the NERC Agrees to Increase New Committee’s Membership.)

“That [demand from members] was pretty loud and clear,” Greg Ford, chairman of the Member Representatives Committee, said Thursday at the MRC’s premeeting informational conference call.

NERC Committee Merger — A new Reliability and Security Technical Committee (RSTC) would replace the Operating, Planning and Critical Infrastructure Protection committees under a plan the NERC board will consider next month. | *NERC*

The SET also eliminated a requirement that committee members have executive-level experience.

The membership also will include representation from each interconnection. “That was a request that came through load and clear as well,” Ford said.

The transition from the three committees to the new Reliability and Security Technical Committee (RSTC) — a revised name from the original proposal, which some stakeholders feared would be confused with the Reliability Issues Steering Committee (RISC) — was also extended into June.

Under the new schedule:

Nov. 5: The board will consider the proposal and RSTC c harter and transition plan. If approved, the board will appoint the new committee’s chair and vice chair at the same time.
Nov. 6 to Dec. 6: Nominations will be open for sector representatives, with sector elections, if necessary, conducted by Dec. 20.
Dec. 9 to Jan. 3, 2020: At-large nominations will be accepted, with the Nominating Committee developing a slate of at-large members by Jan. 15 for presentation to the board.
Feb. 6: Board appoints RSTC sector and at-large members.
Feb. 7 to May 29: RSTC develops transition plan and work plans for RSTC and subcommittees.
March 3-4: OC, PC and CIPC meet. The RSTC will hold its first meeting March 4 to establish the Nominating Subcommittee, Executive Committee and perform other administrative items.
June 2020: OC, PC and CIPC will meet for final work plan approvals and to complete any other approvals. The RSTC will hold initial regular meeting with subcommittee reports and other agenda items.

Terms for the new committee members will expire in June of alternating years. The initial membership will be split between two- and three-year terms, after which terms will run for two years.

The proposed changes didn’t come without misgivings from some stakeholders. (See NERC Board Hears Debate over Committee Reorg.) But Ford said he was happy with the way the process played out.

“There was a lot of open, honest, good discussion all the way back to the first meeting [the SET] had,” he said. “I feel like we’re in a good place.”

He had special praise for the work of Exelon’s Jennifer Sterling and NERC Chief Engineer Mark Lauby. “I thought you herded us cats very well,” he joked.

MRC Governance Guidelines, EMP Task Force

Thursday’s preview of the MRC’s Nov. 5 meeting also included a discussion of revised Governance Guidelines, which were developed to reduce the number of documents guiding the committee to just two: the guidelines and the NERC Bylaws. The Approved Policy on Minutes of MRC Meetings, Framework for the Operation of the MRC and NERC MRC Reference Document would be eliminated.

NERC Director of Engineering and Standards Howard Gugel also provided a brief update on the Electromagnetic Pulse (EMP) Task Force’s Strategic Recommendations Report.

The comment period on the draft report closed at the end of September. (See EMP Task Force Calls for Federal Funding.)

The task force will review the comments and finalize their recommendations in October for presentation to the board at the Nov. 5 meeting.