More MISO Members Join Call for Tx Planning Change

By Amanda Durish Cook

CARMEL, Ind. — A growing number of stakeholders are prodding MISO to create a task team to improve transmission planning assumptions and devise ways to prevent new generation projects from becoming responsible for most transmission development.

Multiple stakeholders at a Planning Advisory Committee meeting Wednesday said MISO’s lagging renewable forecasts and increasingly pricey network upgrades for queue projects merit examination by a new task team.

Clean Grid Alliance’s Natalie McIntire said MISO’s 15-year futures — even the accelerated fleet change scenario — project smaller renewable growth than indicated by projects that have already signed interconnection agreements in the queue. Projects set to come online in the next few years eclipse all futures expectations, she said.

Representatives from the Organization of MISO States and CGA appeared before the RTO’s Board of Directors in mid-September to warn about the increasing trend of otherwise economically viable renewable projects exiting the queue because of prohibitively expensive network upgrades. (See MISO Readies MTEP 19, Debates Futures Change.)

MISO has promised to evaluate special, targeted economic planning studies in its 2020 Transmission Expansion Plan (MTEP 20), while postponing a futures overhaul until the 2021 cycle. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.) During the PAC meeting, MISO project manager Sandy Boegeman asked stakeholders for suggestions on the targeted studies.

Several members have said the RTO cannot afford to wait another year before recasting its future scenarios. MISO will essentially snub transmission projects designed to help facilitate the renewables growth indicated by the interconnection queue, creating a self-fulfilling prophecy, they say.

The accelerated fleet change future should now be considered MISO’s base case future scenario, while the three other futures are “not at all representative of what we might expect,” McIntire said Wednesday. She called for a “better alignment” between planning assumptions and queued generation projects.

McIntire said the Helena-to-Hampton Corners second circuit project should be included in MTEP 19 as a market efficiency project, a contention her organization already put before the board. (See MISO Readies MTEP 19, Debates Futures Change.) The $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study, was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.

McIntire said there was “not a very robust stakeholder process” around testing of the project, which should have been subject to more vetting and a PAC review.

She also said network upgrades borne by new generators in the queue “provide benefits well beyond simply interconnecting generators.” She pointed out that the February 2017 definitive planning phase studies showed that the batch of projects needed more than $1.3 billion in upgrades, an average of $1.5 million per megawatt of new generation.

“It is not efficient or cost-effective for MISO to plan the system one interconnection queue at a time,” said McIntire, who issued the first call for a task team to examine network upgrades and transmission planning. She said MISO should also consider creating a new transmission project category that allows for cost sharing between generators and load.

At a special workshop on MTEP futures Thursday, MISO Planning Manager Tony Hunziker said the RTO is developing a strawman proposal on new futures development for stakeholder review at an Oct. 17 workshop.

Hunziker agreed that industry projections are already “outpacing” even MISO’s accelerated fleet change future, which predicts wind and solar will account for 29% of capacity by 2033. He said there are signs that wind and solar generation will make up more than 30% of the generation mix by that time.

CGA’s Sean Brady noted that some MISO states are targeting a 40 to 50% renewables mix by the mid-2030s.

Veriquest Group’s David Harlan said MISO’s reliance on planning for new generation based on a reliability-focused planning reserve margin might now be “too narrow” to use in transmission planning. He said MISO should consider that the future generation portfolio will have ramping, reactive power and voltage support needs among others.

Hunziker said MISO could move to a “dynamic” — instead of static — planning reserve margin for transmission planning. Though still undefined by the RTO, a dynamic planning reserve margin could change in out-years based on forecasts. Currently, MISO’s futures ensure its planning reserve margin is met.

Some stakeholders have also suggested MISO create a member survey to better capture its members’ carbon-reduction goals and resource additions and retirements.

MISO is also asking whether it should split its footprint into subsections for planning studies or allow for different input assumptions at the local resource zone level, state level, or the MISO Midwest and South regions. Hunziker said subregional futures would require significantly more work.

September 26, 2019

CPUC Opens Investigation of PG&E Bankruptcy Plan

By Hudson Sangree

The California Public Utilities Commission opened a formal examination into Pacific Gas and Electric’s Chapter 11 reorganization plan Thursday, as bondholders trying to take over the bankrupt utility upped the ante by offering wildfire victims $6 billion more than the utility has proposed.

The commission voted unanimously for an order instituting investigation (OII) that will consider how PG&E’s plan to emerge from bankruptcy will affect ratepayers. The CPUC must approve any proposed plan for its reorganization.

“The commission is party to the Chapter 11 matter in the bankruptcy court and will continue to represent the interests of California in this matter,” new CPUC President Marybel Batjer said from the dais. “The commission’s focus remains solely on ensuring Northern Californians receive safe and reliable service at reasonable rates and consistent with achieving California’s climate goals.”

Among the CPUC’s considerations are PG&E’s compliance with AB 1054, a new law that lets the state’s investor-owned utilities participate in a $21 billion fund to pay for fire damages. The caveat is that PG&E must satisfy the requirements of AB 1054 and emerge from bankruptcy by June 30, 2020, if it wants to benefit from the state’s insurance-like fund. (See Calif. Lawmakers Rush to Pass Utility Wildfire Aid.)

California PUC — The California Public Utilities Commission’s headquarters are in San Francisco’s Civic Center district. | © *RTO Insider*

The deadline has lent new urgency to reorganize the company, which faces billions of dollars in debts from the recent wildfires sparked by its equipment. Those fires included the November 2018 Camp Fire, the deadliest and most destructive in state history, and the Northern California wine country fires of October 2017. The expected liability for the fires drove PG&E to seek bankruptcy protection in January.

The commission said Thursday that the broader scope of its investigation would provide more opportunity for public input than the relatively limited scope of the bankruptcy proceedings.

“As much as we get criticized for being complicated and arcane, we are nothing compared to the bankruptcy court,” Commissioner Liane Randolph said, prompting laughter. “So this really is the opportunity for parties with more diverse interests to participate in a somewhat more publicly accessible process.”

Commissioner Clifford Rechtschaffen noted that the OII was familiar ground for the CPUC, which had to approve PG&E’s bankruptcy reorganization plan following the California energy crisis of 2000/01. He said he was confident the commission could deal with the matter “expeditiously.”

The CPUC will focus on the safety concerns that have plagued PG&E since the San Bruno gas pipeline explosion of 2008, which resulted in the commission’s ongoing investigation into the utility’s safety culture, Rechtschaffen said.

Bondholders Push Harder

Two blocks away from CPUC headquarters in San Francisco, in the U.S. Bankruptcy Court for the Northern District of California, a group of PG&E bondholders increased their offer to fire victims in a reorganization plan they want the court to adopt.

The plan by the Ad Hoc Committee of Senior Unsecured Noteholders would seize control of the utility from its current shareholders. The committee has asked bankruptcy Judge Dennis Montali, for a second time, to end PG&E’s period of exclusivity, the time the company has to offer and solicit support for its own reorganization plan, unhampered by competing proposals. (See Lawyers Clash in PG&E Bankruptcy Hearing.)

A hearing to consider that motion is scheduled for Oct. 7.

In a term sheet filed with the court Wednesday, the bondholders said they would invest $29.2 billion in PG&E in exchange for 59.3% of the company’s common stock. Their terms also require PG&E to pay or recast billions of dollars in unsecured debt, which typically can be refuted in bankruptcy.

The term sheet lists more than $17.5 billion in unsecured notes among PG&E’s debts.

The bondholders, led by hedge fund Elliott Management Corp., recently announced they had the support of fire victims after pledging to fund a trust of $13 billion to pay for wildfire damages. In the term sheet filed Wednesday, they upped that offer to $14.5 billion plus another $11 billion to pay subrogation claims held by insurers and others.

PG&E, in its latest Chapter 11 plan, allotted $8.4 billion for a fire-victim trust, though it could increase that amount.

The utility told Montali that it has about $14 billion in financial commitments from banks and investors to help pay for its bankruptcy plan.

PG&E’s plan also includes $11 billion for subrogation claimants, who are now on the utility’s side. Those claimants include Boston-based Baupost Group, another high-risk investor, that bought up a reported $3.3 billion in subrogation claims from insurance companies. Baupost is a major PG&E shareholder that bought the utility’s stock when it was selling for $30 to $40/share instead of today’s roughly $10/share value.

PG&E’s critics said Baupost bought the insurance claims for pennies on the dollar and is trying to profit from the utility’s $11 billion payment plan, partly to make up for its stock losses.

PG&E asked Montali on Wednesday to extend its window of exclusivity from late November to late January. It filed a document in support of that move from John Boken, managing director of AlixPartners, a firm that’s providing interim management services to PG&E during its bankruptcy.

Boken assured the court in his declaration that the company had made a good-faith effort to move forward with one of the biggest bankruptcies in U.S. history.

Given PG&E’s size and the complexity of its bankruptcy, “I believe the debtors have made significant progress in the administration of these Chapter 11 cases,” Boken told the judge.

September 26, 2019

PJM Suspends Auction Deadlines Pending FERC Action

Storage Changes also in Limbo

By Christen Smith

VALLEY FORGE, Pa. — PJM told its Markets and Reliability Committee on Thursday that all deadlines for upcoming capacity auctions will be suspended pending FERC action on the RTO’s proposed revisions to its capacity market.

The news follows Commissioner Richard Glick’s disclosure that he will recuse himself from any matters involving his former employer, Avangrid, until Nov. 29, after FERC’s designated agency ethics official changed his interpretation of an ethics pledge signed by all presidential appointees under an order from President Trump. Avangrid has filed comments and testimony in the case, and Glick has indicated he won’t seek a waiver. (See Glick Recusal May Mean No MOPR Ruling Before December.)

PJM had anticipated commission action before the end of year, when many deadlines for the 2023/24 Base Residual Auction would come due. (See “Capacity Auction Ruling Anticipated Before 2020,” FERC Halts PJM Capacity Auction.)

“PJM is not going to run forward with any BRA-related deadlines until we receive a FERC order and can establish a timeline from that order,” said Jen Tribulski, the RTO’s associate general counsel. The suspension applies to all future delivery years, though PJM will continue running Incremental Auctions for all previously completed BRAs.

Glick’s recusal also leaves the RTO’s second Order 841 compliance filing (ER19-469) in limbo, said Andrew Levitt, PJM’s senior business solution architect for applied innovation.

Although Avangrid was not a party to PJM’s compliance filing, Levitt said it’s unclear whether Glick will sit out from issuing an order ahead of the filing’s requested Dec. 3 implementation date.

Meanwhile, PJM plans to proceed with the multi-use, load-serving energy storage resource (ESR) settlement provisions approved in docket ER19-462. The pending changes detailed in docket ER19-469 — which deal with real-time and day-ahead market changes and billing related to charging ESRs that take transmission service — will be placed on hold. Instead, PJM will adhere to status quo rules, which allow ESRs to participate in all its markets and will count battery charging as “negative generation” that does not take transmission service.

September 26, 2019

Despite Pushback, MISO Pursuing TO-only SATA

By Amanda Durish Cook

CARMEL, Ind. — MISO plans to file its first storage-as-transmission asset (SATA) ruleset next month, despite complaints from some members that the proposed provisions limit resource ownership to transmission owners.

Speaking at a Sept. 25 Planning Advisory Committee meeting, DTE Energy’s Nick Griffin said he and others still see an “equality” issue with the ownership restriction. Griffin has told MISO’s Board of Directors that if the provision remains in the filing, DTE would file a protest in the docket arguing that similarly situated parties stand to be treated inequitably. (See MISO Firming Up 1st SATA Ruleset.)

Discussion at the PAC meeting quickly waded into murky waters over what it means to be a TO and what constitutes a transmission asset.

Griffin has suggested a compromise in which MISO allows non-TOs to own storage that provides reliability transmission services while simultaneously completing the approximately three-year interconnection queue to allow the asset to become a market-based generator. The resource would initially be classified as a transmission asset, then transition to a market resource.

“We can’t defer transmission unless we have an assurance that the transmission alternative” will be there, MISO Director of Planning Jeff Webb said. “If it’s built and constructed and goes into service — and it can’t participate in the market until it goes through the queue — what if it never goes through the queue? Who pays for that? Where are you going to get your cost recovery?

“That’s the fundamental problem we’re having: What is a transmission asset? This feels like a transmission asset owned by a non-transmission owner,” he said. “I’m really worried about the slippery slope here; it’s a gateway drug. The next question might be, ‘Hey, can I do this with a peaking gas generator?’ … We have to find a place for [SATA] that respects our framework.”

“I think already in this process there’s a lot of gray area between transmission and non-transmission assets [NTAs], and unfortunately, that’s where FERC has left us,” Clean Grid Alliance’s Natalie McIntire said. Part of the gray area stems from MISO not having a particularly clear definition of NTAs, she said.

“The dream I have is we would abolish the term ‘non-transmission alternatives’ and define it for what it is versus what it’s not,” Webb said.

MISO has one SATA project proposed for Wisconsin in this year’s Transmission Expansion Plan (MTEP), making the filing a bit of a race against the clock because the RTO doesn’t yet have cost recovery in place. (See MTEP 19 Could Yield First MISO SATA Project.)

Webb said it’s unlikely that FERC will rule on the SATA rules by the board’s approval of MTEP 19 in December. Because MISO doesn’t want to proceed with an uncertain project, it will likely formally recommend the storage project after the usual December timeline. PAC Chair Cynthia Crane said RTO planning staff can appear before the board at the March 2020 meeting to make a one-off recommendation for a project.

MISO last month began drafting SATA provisions to be included in its business practices manual covering transmission planning processes. The drafts place several mentions of electric storage resources into BPM 20, the existing rules on selecting NTAs in place of transmission projects. The provisions would add an inverter-based reliability analysis and allow the RTO to consider the life cycle, degradation and cost assumptions of storage resources, as well as the impacts on proposed generation in the interconnection queue. The changes would also require SATA operators to develop an operating guide for each asset approved in the MTEP process.

But MISO will now put the proposed BPM edits on hold, pending the outcome of the FERC filing, responding to the complaints of stakeholders who said they were premature. Several members said MISO shouldn’t create BPM provisions before defining a method for evaluating SATA projects.

“The BPM was a vehicle to vet changes,” Webb said, explaining the BPM is subject to revision to align with whatever version of Tariff revisions FERC accepts. He said the minimal BPM edits are simply the “essential features” to implement SATA.

September 26, 2019

Supply Side not Buying ISO-NE’s ICR Numbers

By Rich Heidorn Jr.

NEPOOL’s Reliability Committee on Wednesday rejected ISO-NE’s proposed installed capacity requirement (ICR) calculations, with unanimous opposition from the Generation and Supplier sectors.

Needing a 60% majority to recommend them to the Participants Committee, the ICR values including and excluding Mystic Units 8 and 9 failed with only 49.65% support.

With the Generation and Supplier sectors unanimously opposed and the Transmission and Publicly Owned sectors unanimously in support, the vote hinged on a split in the Alternative Resources sector (8.71% in favor, 11.78% opposed). The End User sector lacked a quorum and was reported 0.98% in favor and 0% opposed.

Excluding Mystic 8 and 9, ISO-NE is proposing a net ICR of 32,495 MW for Forward Capacity Auction 14 (2023/24), a reduction of 1,255 MW from FCA 13.

The committee did approve a 941-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14 including the capacity associated with Mystic, and a 943-MW HQICC excluding it.

NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, Bruce Anderson, vice president of market and regulatory affairs for the New England Power Generators Association, explained the generators’ objections after the meeting. He said the reduced net ICR from FCA 13 “will undoubtedly put downward pressure on prices if accepted by FERC.

ISO-NE installed capacity requirement — The system demand curve shows an installed capacity requirement (ICR) of 32,495 MW for Forward Capacity Auction 14 (excluding Mystic 8 and 9), a reduction of 1,255 MW from FCA 13. | *ISO-NE*

“NEPGA has raised a number of concerns with how the ISO modified its load forecasting methodology, which drove the decrease in NICR, including that it was done based in part on only a handful of days in summer 2018. We also believe that ISO-NE may not properly recognize that the peak-load hour is moving farther out due to solar penetration, and thus there may be actual less peak load shaving coming from the behind-the-meter solar than is shown in the load forecast,” Anderson said in an email.

“In addition, ISO-NE has changed the load forecast methodology for purposes of calculating demand (the NICR) but not for purposes of calculating the cost of new entry (for which the load forecast is a significant variable). This inconsistent application of the change in load forecast methodology will cause the FCA to price capacity below its economic price.”

Other stakeholders who criticized the RTO’s calculations declined, or did not respond to, requests for comment.

“Developing the installed capacity requirement is a complex calculation involving many factors. The ISO develops the ICR according to national and regional power system reliability standards and requirements,” ISO-NE spokeswoman Marcia Blomberg responded. “For stakeholders, there may be other considerations.”

Opposition in 2018

It is at least the second year in a row that ISO-NE has faced opposition to its ICR calculations.

Last September, the committee approved an ICR value of 34,719 MW without Clear River Unit 1 for FCA 13, with more than 65.% support. But the RTO’s 34,739-MW ICR with Clear River failed with only 50.01% support. In October, the Participants Committee voted likewise on the two values.

In January, FERC approved the 34,719-MW ICR after accepting the termination of Clear River’s capacity supply obligation for 2021/22 (ER19-291).

FERC approved the ICR values over protests from NEPGA, FirstLight Power Resources and the New England States Committee on Electricity (NESCOE).

NESCOE complained that the filing by ISO-NE and NEPOOL failed to justify increasing system reserves to 700 MW from 200 MW, the level it had been at since 1980. NESCOE contended that ISO-NE was trying to justify its ICR value rather than determining the amount needed to support resource adequacy.

FERC defended the 700-MW reserve level as “a matter of engineering judgment.” It noted that the system’s peak load had nearly doubled since 1980 from about 15,000 MW to 28,000 MW today. The single largest contingencies in 1980 were two nuclear units of 800 to 900 MW each. “Today, New England can experience a single credible contingency of up to 2,000 MW associated with the Phase II interconnection with Hydro-Québec and three other large credible contingencies ranging between 1,250 [and] 1,650 MW each,” FERC said.

FirstLight and NEPGA objected that the ICR-related values used in ISO-NE’s ICR study are based on lower outage rates and higher tie benefit assumptions than those used in the RTO’s fuel security study.

The commission said the generators’ request to calculate ICR using the assumptions from the fuel security study would violate the Tariff.

“These two study processes are distinct and seek to achieve different objectives,” the commission said. “While ISO-NE uses the ICR-related values to address an installed capacity problem, it uses the fuel security study to address a different problem: whether capacity procured in the Forward Capacity Market has sufficient fuel necessary to produce energy needed to meet demand and maintain required operating reserves. That is, a region may have sufficient installed capacity but insufficient fuel to produce energy from that capacity.”

FCA 14 vs. 13

The new ICR values show a 1,065-MW reduction in the load forecast from FCA 13, including a 965-MW drop in the gross load forecast and a 105-MW reduction from updated estimates for behind-the-meter PV generation. The load also was affected by changes to the load forecast methodology, including the addition of a second weather variable (cooling degree days), the separation of the July and August peak load model, and the shortening of the historical weather period from 40 to 25 years.

Also reducing the ICR were improvements to system outage rates.

Those reductions were partially offset by a reduction in tie benefits (+70 MW) and the load relief assumed obtainable from implementing a 5% voltage reduction (+150 MW).

Other Action

In other action Wednesday, the Reliability Committee approved a number of projects, including Exelon Generation’s plan to replace the excitation controllers and automatic voltage regulators (AVRs) at Mystic 8 and 9. The company will install ABB UNITROL Static Excitation Systems at each generator to provide excitation current to the exciters and replace the existing AVRs. They are expected to be in service in October.

Members also approved revisions to:

Operating Procedure 19 to allow adjustments to phase-shifting transformers or reactive flow to maintain system reliability.
the reactive capability audit request form to clarify the types of tests that can be selected on the form.
Planning Procedure 10 to delete provisions related to interconnection service adjustments (Sections 7.7 and 7.8), which are being moved to a new section in the Open Access Transmission Tariff. The change won’t take effect until FERC approves the Tariff amendment.
Sections I.2.2 and III.12.6 of the Tariff to allow the inclusion of competitively developed transmission solutions into the FCM network model.

September 26, 2019

MISO Zeroes in on Queue Overhaul Filing

By Amanda Durish Cook

CARMEL, Ind. — MISO will soon take a second crack at getting FERC approval for Tariff revisions intended to thin out and speed up its overflowing generator interconnection queue.

The RTO is targeting a refiling of the rule changes by early October, a few months later than originally anticipated. (See MISO Makes Second Attempt at More Rigorous Queue.)

The commission in March rejected the RTO’s plan to impose more stringent site control requirements and increase milestone payments for interconnection customers, but it agreed the changes would reduce speculative and duplicative projects. (See MISO Promises Refile on Stricter Queue Requirements.)

Speaking Wednesday at a Planning Advisory Committee meeting, Resource Interconnection Planning Manager Neil Shah made clear that the proposal is no longer up for debate. He began his presentation on the plan with an anecdote about a fixed-price, no-haggle experience at a car dealership.

“So, me, in front of you, I feel like that” car salesperson, he joked.

Shah said MISO’s queue is in dire need of the firmer site control requirements and milestone fees outlined in the plan, adding that a large volume of unready projects translates into inflated costs and cost volatility for other queued projects. The queue now includes 590 projects totaling about 92 GW after hovering around 100 GW for most of this year. In the last three years, about 800 projects comprising about 120 GW have entered the queue.

“We’ve seen projects with power purchase agreements, projects with provisional [generator interconnection agreements] forced to withdraw because of high costs,” he said.

Shah pointed to the February 2017 cycle of projects entering the queue as an example. Of 27 projects at 3.4 GW joining the queue, only two at 250 MW cleared. As a result, the MISO system went from requiring an estimated $3.4 billion in network upgrades to not needing a single one.

While the penalty-free “off-ramps” incorporated into the queue in 2017 are working as intended, MISO still needs a means to discourage unprepared project owners from prematurely lining up for interconnection in the first place, Shah said.

“It still needs adjustment up front,” he said.

MISO’s proposal would require developers of proposed generating facilities to demonstrate site control 90 days before a project enters the first phase of the three-phase definitive planning phase (DPP). It would also eliminate the RTO’s current practice of accepting a $100,000 deposit in lieu of proof of site control.

The refiled plan will no longer seek changes to the queue’s first milestone payment, which will remain $4,000/MW instead of becoming a variable cost representing 10% of the average network upgrade costs from the last three DPP cycles. The new plan will also add a refund mechanism to the total milestone fees imposed on a customer. The “true down” feature would cap total milestones at 20% of a project’s network upgrade cost, with any excess payment refunded back to interconnection customers after a project clears the second decision point, roughly 220 days into the queue.

As with MISO’s first filing, 50% of milestone fees would be considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw.

Additionally, MISO will now allow different fuel types and multiple generation projects to share the same site, scrapping the first proposal’s requirement that project owners show exclusive use of land.

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.)