Page 1192 – RTO Insider

September 26, 2019

Comments Open on Draft 2 of Inverter Standard

By Rich Heidorn Jr.

NERC is accepting comments until Nov. 4 on the second draft of a revised standard to improve the ride-through performance of inverter-based resources (PRC-024-3: Frequency and Voltage Protection Settings for Generating Resources).

The standard is intended to address issues identified in the Inverter-Based Resource Performance Task Force’s PRC-024-2 Gaps Whitepaper, which was prompted by the August 2016 Blue Cut wildfire, when 1,200 MW of solar generation disconnected, and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW.

The 45-day comment period opened Sept. 20 after a Sept. 4 webinar, at which the standard drafting team (SDT) explained changes made in response to industry comments on the initial draft. (See Comments due July 26 on Revised Inverter Standard.)

Draft 2 increases the implementation plan to 24 months from the original 18 months, which was criticized as too short.

Definitions

The term “point of interconnection” — which the current standard defines as the “the transmission (high voltage) side of the generator step-up (GSU) or collector transformer” — was eliminated.

The original term “meant so many different things to different entities,” explained SDT Chair Bryan Burch, of Southern Co.

“What a lot of folks call the point of interconnection in industry is actually not the high side of the GSU,” added Vice Chair Jeff Billo, of ERCOT.

The new draft also replaces the term “momentary cessation” with “cease to inject current.”

“The team talked about that with the inverter industry and … we came to the conclusion that the best path was to eliminate the use of the term ‘momentary cessation’ and go instead with the term ‘cease to inject current’ to better specify the intent and be more uniformly understood,” said team member John Anderson, of Xcel Energy.

The standard also replaces the term “protective relays” with “protection” to include both relays and protective functions embedded in control systems.

No-trip Zone

The team also eliminated the label “may-trip zone” from illustrations in the standard.

“There were comments made that we were then encouraging people to set their protection to trip before there were any machine requirements requiring that trip,” Anderson said. “As a response, the drafting team has eliminated these ‘may-trip zone’ labels on our curves and instead specified with a footnote that the area outside the no-trip zone is not a must -trip zone — hopefully to eliminate encouraging people to set their relay to prematurely trip.”

“The true intent, which is not enforceable on our end, is that we don’t want the protection to encroach on that boundary,” Burch said.

NERC inverter standard — Proposed revisions to PRC-024 would eliminate the label “may-trip zone” from illustrations in the standard to avoid premature generator tripping. | *NERC*

The team declined requests to specify what voltage protection settings should be beyond four seconds after a fault, saying anything after four seconds was outside the scope of the standard.

“We did a lot of research on this — looking back at what went into the original PRC-024-1 determination — and we pretty much found that this whole purpose of this standard was to define these frequency and voltage excursions that might be experienced during and after the clearing of a fault,” Anderson explained. “And we pretty much came to the conclusion that we didn’t have any basis to change that four seconds from the determination that was originally applied in PRC-024-1.”

Conflict with PRC-005-6?

The team was asked whether the standard would cover control systems such as automatic voltage regulators (AVRs) and, if so, how the initiative would mesh with a separate one to revise PRC-005-6. That standard authorization request says the standard needs clarification so that industry can “consistently identify and implement the required maintenance activities” on AVRs.

Anderson said PRC-024 would cover AVRs. “If it causes tripping of the generator either directly [or indirectly], then it is in scope,” he said.

“We can’t really commit to what the PRC-05 SAR and drafting team will do. We can specify that AVRs’ trips on voltage frequency and volts per hertz are in scope for PRC-024. PRC-05 might have other field-over-current-type functions that aren’t applicable to PRC-024,” he continued. “PRC-05 also deals with maintenance of those components, and we’re just dealing with the settings. So, there’s certainly some potential for misalignment. But since PRC-024 is focused on voltage and frequency — volts-per-hertz-type settings — potentially there will be some commonality.”

6 Questions

In its posting of draft 2, the SDT asked industry six questions, including whether the proposed changes are a cost-effective way to address the “ambiguities, inconsistencies and technical errors” in the existing standard.

The team also asked for comment on its decision not to make the standard — which covers the setting of voltage and frequency protective relays on GSU transformers and collector transformers — applicable to transmission owners in the U.S.

No TOs have been identified in the U.S. as owners of such transformers. However, the standard would apply to Hydro-Québec TransÉnergie, which owns the GSUs for about 37 GW of generation that it does not own. (See Tx Owners to be Exempt from Inverter Standard.)

The team also sought feedback on:

its modification of the “facilities” section to clarify both the types of “protection” applicable, if activated, and the specific equipment the protection is applied on;
exempting auxiliary equipment and associated protection(s) within a generating facility from the standard;
replacing the 0.1-second “minimum time (sec)” value in the frequency tables with “instantaneous,” and clarification regarding frequency calculation/measurement; and
the revised implementation plan, which would provide 24 months for applicable entities to evaluate settings, make changes for applicable equipment and purchase necessary equipment.
An additional 10-day ballot for the standard and a nonbinding poll of the violation risk factors and violation severity levels is expected Oct. 25 to Nov. 4.

NERC board adoption is targeted for February 2020.

September 26, 2019

NERC Operating Committee Briefs: Sept. 10-11, 2019

MINNEAPOLIS — The NERC Operating Committee got a preview of GridEx V, an update on ERCOT’s summer operations and a briefing on the June blackout in Argentina at its Sept. 10-11 meeting. Here are some of the highlights.

Argentina Blackout Briefing

NERC senior engineer Hugo Perez gave a joint Operating and Planning committees meeting a briefing on the June 16 blackout that left most of Argentina and Uruguay without power for up to 14 hours. Some 48 million people were left in the dark. Perez based the briefing on a July 3 presentation by Argentina’s minister of energy to the country’s Senate and research by the University of La Plata in Buenos Aires.

The incident on the Sistema Argentino de Interconexión (SADI) occurred shortly after 7 a.m. on a Sunday morning when Argentina’s grid had only 13,000 MW of load, well below its system peak of more than 26,000 MW.

Perez said the problem began when a 500-kV line from Colonia Elia to Belgrano suffered a single-phase fault at 7:06:24. (The cause of the fault had not been identified publicly, Perez said.)

The line is ordinarily supplemented by another 500-kV line from Colonia Elia to Campana, but that line was out of service for construction. To maintain the bus at Campana, the system was operating with a “bypass” from the Colonia Elia-Belgrano line to Campana.

At the time of the fault, Colonia Elia-Belgrano was carrying 1,650 MW from the north to the south. When the line tripped, the system should have sent a signal to generation in the north to reduce output by 1,200 MW to avoid overgeneration that could result in over-frequency.

“They do have procedures in place for outage coordination like we do, so they’re familiar with the concept,” Perez said. “But they didn’t consider that under a new topology they needed to re-evaluate their scheme. … One of the settings at [the north] end was wrong … saying decrease [generation] by zero.”

By 7:06:26, an area in the northeast, including part of Argentina and all of Uruguay, separated from the rest of the system. After teetering for a few seconds, that part of the grid collapsed.

“The blackout could have stopped there, but it didn’t,” Perez said, because the underfrequency load-shedding scheme failed on the remainder of the system.

Only “75% of their underfrequency load shedding that they have designed to operate under these conditions operated correctly; 25% of it didn’t. But things didn’t stop there.”

About two seconds after the initial fault, five generators representing “a significant portion of their generation” disconnected from the system prematurely.

Frequency dropped from 50 Hz to an initial nadir of 48.2 Hz within six seconds. Frequency rebounded for about 20 seconds, rising to about 48.5 Hz before collapsing when other generators disconnected as planned to prevent damage.

“It took them 30 seconds for them to lose not only the island in the northeast but also the rest of the interconnection,” Perez said.

He said the incident suggested a gap between “what was on paper and what was in reality.”

“They know what they need to do. The question is are they really doing it in the field?” he asked. “When you see that underfrequency is not operating as expected … it just begs the question: Are they testing their relays? If they are, how often?”

Lessons Learned: 115-kV Breaker Failure

Kelly McFarlane, an electrical engineer from Bonneville Power Administration, shared lessons learned from a Jan. 5 incident in which a tree fell into a 115-kV line during a winter storm, resulting in an outage for almost 42,000 customers of the Clark County Public Utility District in Washington state.

The tree broke a C-phase conductor, which made permanent contact with the grounded tower.

McFarlane said breakers at both ends of the line properly tripped to clear the fault, then attempted a reclose before tripping back open because of the fault. After the second trip, one of the breakers attempted eight recloses into the faulted line before faulting internally.

ABB, the manufacturer of the failed breaker, helped identify the cause of the problem: Although the instructions call for a 2- to 4-mm gap between the top of the close-coil plunger and the close lever in the breaker’s FSA-2 closing mechanism, there was no gap in this breaker.

The troubleshooting team found felt-tip markings on the breaker, suggesting the problem had resulted from prior maintenance work. The team developed a procedure for field personnel to identify and correct the problem on other breakers on the system.

“We didn’t have a step to check for this gap in our maintenance guide,” McFarlane said. “We do now.”

ERCOT Summer 2019

Dan Woodfin, ERCOT’s senior director of system operations, gave the committee a recap of the Texas grid operator’s summer, in which it had 70,000-MW peaks almost every day in August — the second hottest August on record, he said.

“We can talk about it retrospectively a little bit now, although it was still 100 degrees [Fahrenheit] on Sunday in most of Texas,” he said. “We’re hoping summer’s nearly gone.”

Woodfin said ERCOT’s tightest conditions came two hours before the daily peak, during a “trough” between the two daily wind peaks: from West Texas in the morning and coastal winds in the afternoon.

ERCOT began the summer with an 8.6% reserve margin. It set a new all-time peak of 74.7 GW on Aug. 12, and it has recorded 11 other demand marks above the record set a year ago. Last year, ERCOT broke its previous record 14 times.

Austin, home to ERCOT, exceeded 100 F during 27 of August’s 31 days.

Prices hit the $9,000/MWh cap during two energy emergency alerts, ERCOT’s first in five years, on Aug. 13 and 15.

“Where does this leave us for next year?” asked Sidney Jackson, of Rochester Public Utilities.

Woodfin said ERCOT has a large number of solar and storage resources in its interconnection queue along with some gas turbines.

“I think it’s too early to say whether we’re going to see big-time interconnection requests as a result [of 2019]. But … those prices were high enough that they should, in theory … incent additional investment.”

GridEx V

NERC’s Tom Hofstetter said GridEx V, scheduled for Nov. 13-14, will feature more government and natural gas industry involvement than in prior exercises. About 330 organizations were registered for the event as of Sept. 3, including 64 government agencies (16 of them states) and 62 gas or gas-electric entities.

GridEx IV, held in November 2017, had more than 6,500 participants, representing 450 organizations.

Votes

The committee:

Approved the appointment of Darrel Yohnk, of ITC Holdings, to replace Gerry Beckerle, of Ameren, as chairman of the OC’s Nominating Subcommittee.
Approved a reliability guideline, Improvements to Interconnection Requirements for BPS-Connected Inverter-Based Resources. The recommendations are applicable to transmission owners developing interconnection requirements for inverter-based resources; generator owners; transmission planners; planning coordinators; reliability coordinators; transmission operators; and balancing authorities.
Endorsed for submittal to the ERO compliance implementation guidance, Data Exchange Infrastructure and Testing Requirements. The guidance provides examples of data exchange infrastructure reference models and tests for redundant functionality.

Save the Date

The North American Generator Forum will hold its annual meeting Oct.15-17 at NERC headquarters in Atlanta.

The North American Transmission Forum will hold a Resiliency Summit on March 31 to April 2, 2020. Details will be available in January.

— Rich Heidorn Jr.

September 25, 2019

Lawyers Clash in PG&E Bankruptcy Hearing

By Hudson Sangree

Lawyers in the Pacific Gas and Electric bankruptcy case argued for hours Tuesday over competing reorganization plans and how much the utility owes to wildfire victims.

The attorneys shot insults at one another at times during the hearing in U.S. Bankruptcy Court in San Francisco. An attorney for fire victims said the utility was treating those it had harmed as annoyances, while an attorney in PG&E’s camp said the plaintiffs’ lawyers had a “credibility problem.”

The new level of testiness came as the case seemed to be moving toward its endgame.

Over the last two weeks, major parties in the bankruptcy divided into two camps, each with its own reorganization plan, and PG&E reached an $11 billion settlement with insurers. That left only one big question: How much will PG&E pay fire victims?

“It does look like some of the important building blocks of what could be a global consensual deal are beginning to fall into place,” attorney Dennis Dunne, with law firm Milbank, told Judge Dennis Montali. Dunne, who represents the official committee of unsecured creditors, called the recent developments “stunning” with “parties that are willing to write substantial checks.”

PG&E — A National Guard soldier searches for remains after the Camp Fire in Paradise, Calif., killed 86 people in November 2018. | *California National Guard*

On Sept. 13, PG&E announced it had reached an $11 billion settlement with subrogation claimants — the insurers and other parties trying to recoup insurance payments to victims of wildfires sparked by PG&E equipment.

As the insurers locked arms with PG&E and its shareholders, wildfire victims teamed up with investors that hold more than $10 billion in PG&E bonds. It was a coup for bondholders, who offered a reorganization plan that would give PG&E billions of dollars in cash in exchange for a controlling stake in the utility.

The bondholders’ plan would pay fire victims $13 billion and the subrogation claimants $11 billion. PG&E’s plan, as it currently stands, would provide a capped trust of $8.4 billion for fire victims in addition to the $11 billion for subrogation claims. (See Judge to hear PG&E Take o ver Plan.)

Montali said he’ll decide whether to allow the bondholders to submit their reorganization plan, to formally compete with PG&E’s proposal, at a hearing on Oct. 7.

Cecily Dumas, a San Francisco bankruptcy attorney, said the fire victims she represents were frustrated and upset, some to the point of tears, that PG&E appeared to be offering insurance companies more money and putting them ahead of people who had lost family members, homes and businesses in the wildfires.

“Regrettably we are in this place … where the victims are lined up behind a creditor plan,” Dumas told the judge.

PG&E, she said, hadn’t shown fire victims a draft of its reorganization plan or met with victims’ lawyers even once.

“They are playing it like we are an irritant, like a rock in your shoe.” Dumas said. “We are not an irritant. We are the communities you burned. We are the loved ones of those whose lives you took. We deserve respect. This is not a chess game.”

PG&E filed for bankruptcy in January, citing $30 billion or more in wildfire damages.

California fire investigators blamed faulty PG&E transmission equipment for starting the Camp Fire, which killed 86 people in Paradise, Calif., and burned down more than 14,000 homes in November 2018. The utility’s equipment started 21 of the 22 the major Northern California fires of October 2017, including three fires that resulted in multiple deaths, investigators with the California Department of Forestry and Fire Protection (Cal Fire) determined.

PG&E is heading toward a trial on the Tubbs Fire, which killed 22 people and destroyed part of the city of Santa Rosa. State fire investigators said a private landowner’s electrical line had sparked the fire, but plaintiffs’ lawyers still hope to convince a jury that PG&E was responsible.

In response to Dumas’ comments, attorney Bruce Bennett, who represents PG&E equity holders, said, “There’s a fundamental credibility problem with the lawyers involved for the wildfire plaintiffs.”

Representatives for fire victims had said, early in the case, that they anticipated about 100,000 claims and uninsured liability of approximately $36 billion, Bennett said. Now they’ve agreed to settle for $13 billion in the bondholders’ plan, and the number of claims may be far fewer than anticipated, he said.

“There’s a problem starting with very high aggressive numbers that are divorced from the actual facts,” he said.

He encouraged the judge to appoint a mediator to help sort out the issue of damages.

Montali noted a separate proceeding in federal court was intended to estimate the amount of wildfire damages PG&E faces. The judge’s ruling in that “estimation proceeding” will be binding, though it would be made moot by a settlement agreement between PG&E and the wildfire victims, Montali said. (See PG&E Bankruptcy Split into Three Parts.)

September 25, 2019

DOJ Weighs in on Texas ROFR Lawsuit

By Tom Kleckner

The U.S. Department of Justice on Friday filed a “statement of interest” with the federal district court hearing an appeal of a Texas law giving incumbent utilities the right of first refusal over transmission projects (1:19-cv-00626).

Assistant Attorney General Makan Delrahim and attorneys from the department’s Antitrust Division sided with NextEra Energy that Senate Bill 1938 violates the U.S. Constitution’s dormant Commerce Clause, which prohibits states from “unduly” restricting interstate commerce or adopting “protectionist measures.”

DOJ said SB 1938 places competition in Texas’ deregulated retail electric market “at risk.” It used as examples a competitive MISO project in southeast Texas recently awarded to NextEra Energy Transmission (NEET) Midwest and a pending application by NEET Southwest for a certificate of convenience and necessity in SPP’s Northeast Texas footprint.

The department said the legislation puts competitive transmission’s benefits “in jeopardy,” with the “likely result” of higher electricity costs, and that SB 1938 “discriminates in favor of companies with a local physical presence.”

Right of First Refusal — | *Cherokee County Electric Cooperative Association*

The bill, passed into law in May, grants CCNs to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)

DOJ also said SB 1938 “diverges from national trends towards more competition that arose after FERC found in the 1990s that it is not in ‘the economic self-interest of public utility transmission providers to expand the grid to permit access to competing sources of supply.’”

NextEra Energy Capital Holdings (NEECH) and four other NextEra transmission owner/developer entities in June filed a lawsuit calling for repeal of SB 1938 in the U.S. District Court for the Western District of Austin. The suit names Public Utility Commissioners DeAnn Walker, Arthur D’Andrea and Shelly Botkin as defendants. (See NextEra Takes Texas to Court over ROFR Law.)

The lawsuit calls for both declaratory relief to invalidate the law and injunctive relief to prevent the PUC from enforcing the law.

NextEra said it has standing because the law jeopardizes its Hartburg-Sabine Junction competitive project in southeast Texas and its acquisition of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative.

Texas Attorney General Ken Paxton was also named as a defendant, but he has since been dismissed from the proceeding.

The Texas Attorney General’s Office last month argued for dismissal of NextEra’s complaint, saying SB 1938 “is simply the codification of the long-time Texas (and successful) practice that the owners of existing transmission lines build out their existing lines from their endpoints.”

SB 1938 is not protectionist, and NextEra does not state a claim under the dormant Commerce Clause, Paxton’s office said. “NextEra has no vested contract rights, only an expectation, with respect to the transmission lines in question. And its rights were always subject to the imposition of new standards in the heavily regulated electric-utility industry.”

An appeals court in August gra n ted Entergy Texas, Southwestern Public Service and Texas Industrial Energy Consumers’ motion to dismiss their appeal of a 2017 PUC order negating an incumbent utility’s ROFR (03-18-00666-cv). The parties filed their request in July, arguing SB 1938 had rendered the case moot. (See SPS, Entergy Fi l e to Pull ROFR Appeal.)

A similar ROFR case is unfolding in Minnesota, with oral arguments scheduled for Oct. 16 in the 9th U.S. Circuit Court of Appeals. DOJ similarly joined the challenge against that state’s ROFR law. (See Justice Dep t . Joins Challenge to Minn. ROFR Law and Court s Uphol d Minn. ROFR, MISO Cost Allocation.)

September 25, 2019

PJM Monitor: Fix DR Capacity Seller Rules

By Christen Smith

PJM’s Independent Market Monitor said the RTO should resume its efforts to close loopholes that allow demand response resources to sell high and buy low in its capacity auctions.

In an analysis published earlier this month, the Monitor concluded that DR sellers bought the highest amount of replacement capacity between 2007 and 2019 — more than internal or external generation sources, both in and out of service, and energy efficiency resources. The Monitor said that statistics support its conclusion that DR market sellers base their offers on speculation, at best, and later buy replacement capacity for a “substantial portion” of those commitments at a discounted price.

“There is no reason for further delay on this matter,” the Monitor wrote. “The evidence has been and continues to be quite clear. The incentives have been and continue to be quite clear. The lack of an enforced specific requirement that all capacity resources be demonstrably specific physical assets when offered into PJM capacity auctions continues to provide strong incentives to offer speculative paper capacity.”

According to the Monitor’s analysis, which focused on June 1 of each year, the share of net replacement capacity for DR commitments exceeded 50% from 2009 to 2011. Between 2012 and 2019, the rate exceeded 20%. The Monitor attributed the decline to PJM’s discontinuation of the Interruptible Load for Reliability (ILR) program.

PJM — Net replacements to cleared capacity by resource classification: June 1, 2007, to June 1, 2019. | *Monitoring Analytics*

In 2014, PJM implemented a rule that required DR sellers to submit a plan ahead of the capacity auction, but the Monitor said that didn’t go far enough. Under existing rules, sellers must only provide site-specific and customer-specific information if their resources are located within a zone of concern that is also in excess of a curtailment service provider’s (CSP) defined sell threshold. Only three zones of concern have been identified — ATSI, Penelec and MetEd — for delivery years 2017/18 through 2022/23.

The Monitor said that without identified customers or clear plans for implementing DR, CSPs can make speculative offers in the Base Residual Auction that do not represent what may be physically available during the actual delivery year.

“The risks to the markets associated with the sale of DR without any supporting information on the plausibility of the underlying assets include the risk that multiple CSPs could be assuming that they will win the same customers and the risk that sellers are taking speculative positions with a low probability of fulfilling them,” the Monitor wrote. “The result in both cases is that the system is less reliable than it might otherwise be because the full amount of DR that cleared the [Reliability Pricing Model] auction is not actually available, the price to other capacity resources has been suppressed by the sale of the speculative DR, new entry of other capacity resources could have been forestalled by the sale of speculative DR, and there may not be adequate replacement resources available with short notice prior to the delivery year.”

PJM — Total replacements to cleared capacity by resource classification: June 1, 2007, to June 1, 2019. | *Monitoring Analytics*

The Monitor said physical generation assets become displaced in the BRA and then have an incentive to offer at lower prices in the Incremental Auctions to recover capacity revenues. Those lower prices permit the buyback of “speculative DR” at lower prices, encouraging the bidding cycle to continue and “creating an unfair advantage … and self-fulfilling dynamic that incents more of the same behavior.”

The problem hasn’t been lost on PJM. The RTO filed Tariff revisions in 2014 to address the issue, but FERC rejected the filing and initiated a proceeding under Section 206 of the Federal Power Act and held technical conference to sort the problem out. In August of that same year, PJM stalled the proceeding in order to collect additional data under its new Capacity Performance construct. In 2018, PJM filed Tariff revisions for its IA procedures in tandem with another deferral on its earlier capacity replacement docket. FERC rejected the auction Tariff filing and terminated the 2014 docket, leaving the issue unresolved.

PJM is reviewing the Monitor’s report, spokesman Jeff Shields told RTO Insider on Wednesday.

“The IMM is correct that PJM has taken steps to further solidify the requirements for demand response to substantiate its physical nature as part of the DR sell offer plans, and additional PJM proposals in this regard have been rejected by FERC. PJM would need to evaluate whether further restrictions are appropriate,” Shields said.

The Monitor urged PJM to pick back up with the docket and change existing rules so that DR sellers must provide evidence of physical commitment from specific and identified customers in the form of a contract signed six months prior to the appropriate capacity auction. It also encouraged limiting replacement capacity transactions to those resources with physical issues.

September 25, 2019

OMS: 4.5 GW of Unregistered DERs in MISO

By Amanda Durish Cook

CARMEL, Ind. — MISO is home to more than 4.5 GW of unregistered distributed energy resources, much of it for nonresidential use, the Organization of MISO States estimates.

The figure comes from OMS’ annual DER survey, which was presented to MISO stakeholders at a special workshop Tuesday.

The total breaks down to 1.2 GW of residential and 3.4 GW of nonresidential capacity, much of which is solar. Unsurprisingly, the group found that residential installations tend to be smaller than nonresidential, said Tricia DeBleeckere, senior planning director for the Minnesota Public Utilities Commission.

DeBleeckere said utility interconnection requests remain the primary source of data on DERs.

This year’s numbers are up sharply over last year’s, which showed 2.5 GW of unregistered DER capacity. OMS said unregistered residential capacity increased by 170% year over year, while nonresidential rose 62%. By comparison, MISO contains about 12 GW of registered load-modifying resources.

OMS also noted that the RTO is home to about 31 DER pilot programs.

Of the roughly 50 utilities that responded to this year’s survey, more than half said they were considering investments that could improve their DER visibility. Eleven said they were considering implementing some type of DER management system.

Still, most survey respondents said they have yet to experience a transmission-level impact stemming from DER use. The utilities also said low natural gas prices appear to be discouraging some types of DER adoption and encouraging others, such as customer-owned combined heat and power.

FERC Sends DER Data Request to RTOs.)

MISO counsel Michael Kessler said the RTO is also still evaluating FERC’s data request before it decides whether to reach out to members for help with DER estimates.

“We’re still figuring out where we’re going on the responses,” Kessler said.

Meanwhile, MISO is still waiting on FERC to provide a clear definition of DER before the RTO begins work with stakeholders on a possible participation model.

“We’re waiting for FERC to define what it is,” DER Program Manager Kristin Swenson told stakeholders.

Swenson predicted that several players will need to be involved to plan for and manage an influx of distributed resources. She also said there is much speculation within MISO over what a possible Notice of Proposed Rulemaking might look like.

“We have to work very closely with regulators on the state level,” Swenson said. “MISO has a piece of this. Transmission has a piece of this. Consumers have a piece of this. … It’s going to take some time, and that’s why we’re here today.”

Estimated unregistered DER in MISO | *OMS*

There are a “million ideas” but “no golden rule yet,” MISO adviser Robert Merring said.

MISO also admits it needs to improve existing market paradigms for more distributed participation, including the registration process, communication system and demand response resource tool, which is used to collect meter data for the settlement of LMRs after they’re called up for emergency events.

“We recognize we have a disparate set of tools to manage these resources, and we’re working on that,” MISO adviser Michael Robinson said.

WPPI Energy economist Valy Goepfrich said the future level of interest in DERs remains an open-ended question. She said integration into the wholesale markets would likely depend on economics but noted that her company’s LMRs currently have little interest in forging ahead into wholesale markets themselves.

“The wholesale market is a tough business. It’s not for the faint of heart. That’s why we’re all regulated utilities,” she said, smiling.

MISO will resume DER workshops in November and through early 2020.

September 24, 2019

NERC Standards Committee Briefs: 9-18-19

The NERC Standards Committee on Wednesday elected Amy Casuscelli as chair and Todd Bennett as vice chair for a two-year term beginning in January.

Casuscelli is a senior reliability standards analyst for Xcel Energy. Bennett is a manager of reliability compliance for Associated Electric Cooperative Inc. (AECI).

The two-year terms of the committee’s 10 segment representatives — including Bennett, the segment 3 representative — also expire at the end of the year. NERC will consider n o minations until Oct. 10.

The committee agreed to hold four in-person meetings in 2020: March 17-18 and Dec. 8-9 at NERC headquarters in Atlanta, June 16-17 in Denver and Sept. 23-24 in Salt Lake City (a joint meeting with the Compliance and Certification Committee). The schedule could be trimmed to three meetings if a fourth is not needed. The committee holds conference calls each month between in-person meetings.

Reliability Standards Development Plan OKd

The committee endorsed the 2020-2022 Reliability Standards De v elopment Plan (RSDP), which will be presented to the Board of Trustees for approval in November.

NERC’s Rules of Procedure require it to provide the plan — which includes schedules and anticipated resource needs for each project under development or expected to begin — to FERC and Canadian and Mexican government authorities. The three-year plan requires the committee to provide the Board of Trustees yearly progress reports.

As of Aug. 31, according to the report, there were 12 outstanding FERC directives, six of which are being addressed in the standards development process. All projects from the previous RSDP are expected to be completed this year, except for seven that will continue into 2020:

Project 2015-09: Establish and Communicate System Op e rating Li m its
Project 2016-02: Modificat i ons to CIP Stan d ards
Project 2017-01: Modifications to BAL-00 3 -1.1 (phase 2)
Project 2017-07: Standards Alignment with Reg i stration
Project 2017-03: FA C -008-3 Periodic Review
Project 2017-04: Periodic Review of Interchange Scheduling and Coordination Standards
Project 2017-05: NUC-001-3 Periodic R e view

Soo Jin Kim, manager of standards development, told the committee the plan will be updated to reflect projects’ status before being submitted to the board.

Actions on Resource Documents

The committee approved revisions to two SC resource documents and the retirement of a third:

Retired will be SC procedure “Approving Errata in an Approved Reliability Standard,” which describes how NERC staff prepares and files errata versions. The procedures have been added to the NERC Standard Processes Manual.
The “Guidance Document for Management of Remanded Interpretations,” will be revised to clarify that the notice provisions are similar to those in Section 309.2 of the NERC Rules of Procedure. It requires notifications be made to FERC and Canadian and Mexican government authorities when a reliability standard is remanded.
“Acceptance Criteria of a Reliability Standard (Quality Objectives),” was revised to clarify the correlation between the document and the SC’s Ten Benchmarks of an Excellent Reliability Standard and FERC Order 672, which established the criteria used to assess standards submitted for FERC approval.

Volunteers Needed

Soo Jin Kim said more members are needed for the standard drafting team Project 2 0 19-04: Modifications to PRC-005-6, although the nomination period has already closed. Project 2019-02 : BES Cyber System I n formation Access Management, which closed Sept. 20, also had vacancies as of Sept. 18, she said.

— Rich Heidorn Jr.

September 23, 2019March 13, 2025

Task Team: Boost Member Role in MISO Board Selection

By Amanda Durish Cook

ST. PAUL, Minn. — A special task team is suggesting that MISO revise its Board of Directors selection rules to give stakeholders a more consequential voice in board makeup.

The Board Qualification Task Team (BQTT), composed of MISO stakeholders, last week released a draft of recommendations, including that the RTO double the number of stakeholder representatives on the Nominating Committee that selects board candidates and rotate the sectors from which committee participants are drawn. (See Task Team Zeroes in on MISO Board Recommendations.)

The recommendation would establish four stakeholder seats on the Nominating Committee, outnumbering the three seats reserved for MISO directors. The BQTT also raised the possibility of reserving one of the stakeholder seats for a representative of the Organization of MISO States.

Task team lead David Bloom, of the Power Marketers and Brokers sector, put the recommendations before Advisory Committee members at their meeting Wednesday. The list is still open to suggestions from the committee, which also extended the life of the BQTT through the end of the year to allow it to tweak the recommendations. The AC will vote individually on them at either its Oct. 23 or Dec. 11 meeting.

Also on the list is a recommendation to require state and federal regulators to observe a yearlong “cooling-off” period before becoming eligible for nomination to the board, a policy that currently applies only to those coming out of the industry. However, the change wasn’t labeled a must-have, as the task team also said it would accept if AC members ultimately don’t see a need to extend the moratorium to regulators.

MISO originally required board members with financial ties to the RTO footprint to observe two-year pre- and post-service restrictions, but it reduced those requirements to a one-year pre-service restriction in 2016.

Finally, the task team also presented options for MISO to either designate one of the nine director seats for those with experience representing utility customer interests or create a new process where RTO sectors could describe what qualifications they’re seeking in new board members. The Nominating Committee selects board member candidates in closed deliberations, assisted by management firm Russell Reynolds.

Reaction to the recommendations was mixed, with some AC members asking why the BQTT preferred a stakeholder majority on the Nominating Committee and others asking why all MISO sectors couldn’t be represented on the Nominating Committee at the same time.

Environmental and Other Stakeholder Groups representative Beth Soholt wondered if MISO’s cooling-off period unnecessarily limits the slate of board candidates. In meetings, the BQTT had mulled eliminating the period altogether.

“We note that [former FERC Commissioner Cheryl] LaFleur was appointed to the ISO-NE board without any cooling-off period. In fact, she’s probably red hot,” Soholt joked. (See LaFleur Elected to ISO-NE Board.)

September 23, 2019

Scant Support for 11th MISO Sector

By Amanda Durish Cook

ST. PAUL, Minn. — MISO stakeholders last week signaled that they’re not yet ready to embrace creating an 11th sector in the RTO’s Advisory Committee to accommodate hard-to-pin-down members.

But discussion on the matter will continue as MISO fields a growing number of membership applications from entities that don’t have goals that clearly align with any of the RTO’s 10 existing sectors — the “others” current housed within the increasingly crowded Environmental and Other Stakeholder Groups sector.

By the end of the AC meeting Wednesday, MISO’s Power Marketers and Brokers sector had offered to absorb the “others” into its fold for a yearlong trial period.

Committee Chair Audrey Penner said MISO could use the time as a period of “discovery” to determine the need for a new sector. “This will be an exploratory year, and I’m very interested in who will line up to join our dysfunctional group,” she joked.

The committee last month considered creating a miscellaneous, 11th sector in order to give its Environmental sector a more singular voice. The committee was weighing whether to spin off the “other” contingent from the sector in response to member requests that entities with miscellaneous interests be separated from those with an environmental focus. (See Advisory Committee Considers 11th MISO Sector.)

The move came with many possible AC voting implications, chief among them how to mete out the Environmental sector’s existing two votes. AC leaders proposed several options, including splitting them; allowing the Environmental sector to retain its votes without giving the new sector a vote; or upping the number of committee votes to allow the new sector to participate in voting.

But a poll released last month revealed a majority of sectors preferred no change at all.

MISO — Alcoa’s DeWayne Todd, of the Eligible End-User Customers sector | © *RTO Insider*

Eligible End-User Customers sector representative DeWayne Todd said he wasn’t convinced about the need for a new sector. He cautioned that, because any undefined entity could join, establishing a unified opinion for AC voting matters could prove “cumbersome.”

“We didn’t see a compelling reason to make a change at this point. We created the [Competitive Transmission Developer] sector when there was a need,” Todd said. The Environmental/Other sector housed some competitive transmission developers briefly before the creation of the CTD sector in 2014. The Sustainable FERC Project’s John Moore recalled conversations within the sector during that time as being stifled.

The Independent Power Producers and Exempt Wholesale Generators sector’s Adam Sokolski said he would have appreciated more conversation on exactly what entities would join a catch-all sector.

As a rule, MISO does not reveal the names of companies that approach it for membership until public approval by the Board of Directors. All members must belong to one of the 10 sectors.

However, it’s no secret that multiple “miscellaneous” companies are clamoring for membership.

“We know that there are companies that are approaching MISO that don’t have a home. What that number is, we don’t know,” Penner said. She reminded the sectors that it’s incumbent upon the stakeholder community to be as inclusive as possible. She also said removing hurdles to membership can further FERC’s goal of RTO transparency.

“I’m going to recharacterize this as an opportunity, not a problem, because more around the table is a good thing as far as I’m concerned,” Penner said. “We need a home for entities to join MISO, but it’s clear the Environmental sector is not a good fit.”

The Environmental sector itself voted to drop the “Other Stakeholder Groups” descriptor, retain its two votes and take no action to create a new sector.

“We would hope there would be a way to give someone a voice without creating a new sector,” Clean Grid Alliance’s Beth Soholt said.

David Bloom of the Power Marketers sector offered to draw up a plan to for “others” to join his sector in time for the committee’s Oct. 23 meeting. He said the switch is dependent on existing members’ agreement.

Director Barbara Krumsiek predicted there will be many more “others” in MISO’s future as the RTO’s energy landscape “remains so fluid.”

September 23, 2019

MISO Members Dissect Implications of Grid Change

By Amanda Durish Cook

ST. PAUL, Minn. — The rate of MISO’s grid transformation is at once distressingly slow and unbelievably quick, RTO members said last week in a session directed at guiding future market decisions.

And no one yet knows how high prices could go when renewables have the lion’s share of the market.

Stakeholders selected a rather broad topic for MISO’s quarterly “Hot Topic” discussion, choosing to focus on the pace of change and new directions in the markets and grid strategy during an Advisory Committee meeting Wednesday.

“This isn’t Festivus. This isn’t the airing of grievances,” moderator Kevin Gunn, an energy attorney and former chairman of the Missouri Public Service Commission, joked as he opened the discussion.

Gunn instead urged the committee to advise MISO on big-picture ways it could transform markets.

John Moore, representing the Environmental and Other Stakeholder Groups sector, called for “more active” cooperation between MISO and its participating states, saying that while the RTO appears ready to roll out more market services and products to meet demand, resource adequacy is ultimately the proprietary role of states.

“When you have high levels of renewable energy on the grid, you’re going to want to make sure you can meet the need, and folks on the distribution side of the grid will play a big role in meeting that need,” Moore said.

Arkansas Public Service Commission attorney Christina Baker reminded MISO and members that public service commissions have jurisdiction over utilities but not the data collection companies that could provide visibility into distributed resource participation.

“It’s a wider range sitting at the table than has been before,” she said.

Municipals, Cooperatives, and Transmission Dependent Utilities sector representative Chris Norton agreed that it was going to take much more communication between MISO and distribution facilities to manage supply.

The Independent Power Producers and Exempt Wholesale Generators’ Travis Stewart pointed to the poor financial outlook for merchant suppliers in MISO. He said the harsh winter in the northern footprint reinforced the need for suppliers outside the usual regulated utilities.

“Consumers really needed those electrons on the system to maintain their quality of life and safety,” Stewart said.

“One of the themes … is how fast this needs to happen,” MISO Director Nancy Lange observed, asking for members’ opinions on the necessary rate of market change.

“We need the price signals that will encourage us to build. And we’d like to see those sooner rather than later, because we’re on a 15-year planning horizon for storage builds,” Advisory Committee Chair Audrey Penner said.

Multiple members said the resource mix is changing much faster than MISO’s current transmission planning can accommodate. The IPPs’ Adam Sokolski said more transmission development is needed now.

“Markets, pricing can adapt a lot faster than transmission planning,” Sokolski said “It’s that transmission side, where we’re going to have to speed up that transmission regulatory review and execution.”

Legacy Costs

But Baker pointed out that customers all over the footprint are still paying for coal plant construction, even though coal plants are now generally deemed obsolete.

“We have to be able to balance that rates are still in the past,” Baker said. “Shiny new things are great,” she said, but she urged utilities and MISO to be mindful of the cost of new builds.

Norton agreed that “shiny new toys” saddle customers with legacy costs over multiple decades. Multiple stakeholders also said that while market pricing is very low today, rates in comparison are high because transmission and generation assets are bundled in.

Several stakeholders asked for fair market prices and incentives across all resources.

The Union of Concerned Scientists’ Sam Gomberg said that he perceived tax credits as a means for renewable resources to play catch-up with other heavily subsidized traditional resources. However, he warned MISO that absolute recovery across all resources is unattainable.

“You can’t ask a nuclear plant to follow load; you can’t ask a wind farm to be available next July 15 at 3 p.m.,” he said.

‘Catch-up’ to Corporate America

Transmission Owners sector representative Jeff Dodd said MISO and transmission owners must find a way to accelerate the study of projects in the interconnection queue.

“Everybody sees these corporate renewable goals and these companies saying, ‘We’re going to get there with or without you,’” Dodd said.

“The biggest buyer of renewable energy is Corporate America, not utilities,” Eligible End-User Customers sector representative Kevin Murray pointed out. “So, the train has left the station — we’re playing catch-up.”

Murray also noted that, the very next day, MISO’s board would decide whether to admit Google as a member in the End-User sector, which it ultimately did. (See related story, “MISO, Meet Google,” MISO Board of Directors Briefs: Sept. 18, 2019.)

To the Disruptors, Goes the … Bill?

Baker said that if utilities pivot to catering to industrial customers with renewable appetites, then rates will have to shift so that companies shoulder more costs of sometimes expensive technologies.

“Why are 60% of costs being borne by residential customers?” she asked rhetorically.

Wisconsin Public Service Commissioner Mike Huebsch added a caveat to what he dubbed a “transformative shift on the side of the angels.” He said a transformation must be tempered so reliability doesn’t suffer. He wondered aloud if “Corporate America” is as ready to accept unintended consequences of 100% renewable energy as it is willing to drive the change.

“It’s not going to be an inner-city townhouse in Milwaukee that loses heat; it should be Google that shuts down for an hour,” he said.

“The pace of change is never going to be fast enough for the threat of climate change,” Gomberg added.

TDU sector representative Kevin Van Oirschot said the conversation reminded him of an oft-repeated line of a colleague at Consumers Energy: “The rate of change will never be this fast again, and it will never be this slow again,” he said to laughter. “I think that perfectly captures this moment.”

“‘With all deli b erate speed.’ Got it,” Gunn summed up the members’ conversation, quoting the infamously vague phrase in the Supreme Court’s Brown v. Board of Education decision.

A day after the talk at the board meeting, Board of Directors Chair Phyllis Currie thanked members for at least the consensus that new measures are necessary.

“We all agree that change is coming. We’ve had some deniers in the past,” she said.