SPP Strategic Planning Committee Briefs: April 15, 2020

SPP Board of Directors Chair Larry Altenbaumer last week asked the Strategic Planning Committee for an education session on congestion hedging following stakeholder disagreement over the best way to proceed with a recommended white paper.

“The SPC’s role needs to come into sharper focus,” Altenbaumer, who also chairs the committee, said during its conference call Wednesday. “The best way to be successful with these recommendations is if they come up through the stakeholder process.”

The Holistic Integrated Tariff Team (HITT) last year recommended that SPP develop a market mechanism to hedge load against congestion charges. The team suggested modifying the existing market design to use only excess auction revenues to fund counterflow optimization positions.

SPP Strategic Planning Committee — SPC Chair Larry Altenbaumer (left) and Vice Chair Mike Wise during a November 2019 committee meeting. | © *RTO Insider*

The HITT directed the Market Working Group (MWG) to develop a white paper documenting a recommended path forward. The group came up with three counterflow optimization options:

Assigning counterflow cost to the market participant after the annual auction revenue rights (ARR) auction’s first round.
Assigning the counterflow cost to ARR surplus after the annual transmission congestion rights (TCR) auction.
Creating a new round in the long-term congestion rights (LTCR) allocation, with the counterflow cost directly assigned to the market participant. If the LTCRs become infeasible, the cost is assigned to the ARR surplus.

The MWG rejected all three options during its February meeting, after having earlier voted to keep the current design for congestion hedging. The group has said the second option satisfies the HITT initiative, but the Markets and Operations Policy Committee rejected the option last week, directing the group to further develop the first option.

“You’re not going to get consensus on this, because a majority of the companies are happy with their hedging portfolios,” warned Bill Grant, with Southwestern Public Service. “When we designed the market, we decided against counterflows. The majority of the group is not recognizing there’s a problem. They’re looking at the monetary value their customers are receiving from current hedging activities.

“The do-nothing option seems to be the one that’s winning the day.”

Keith Collins, executive director of SPP’s Market Monitoring Unit, said his team doesn’t have a preferred proposal but is considering developing its own mechanism “that could address the concerns of HITT and others.”

“Our view, as a neutral entity, is that the options have pros and cons. There are no clear-cut winners,” he said. “These are very complex issues. The TCR process is complex, but some of these solutions have additional layers of complexity. We’re happy to be engaged to find a solution.”

Committee Endorses 2 HITT Recommendations

The SPC endorsed two additional HITT recommendations that passed the MOPC the day before: the establishment of uniform Schedule 9 local planning criteria and the elimination of Z2 revenue crediting.

The committee approved the local planning criteria 9-1, with three abstentions. The elimination of Z2 crediting passed 12-0, with one abstention.

SPC members repeated some of the same concerns they had expressed during the MOPC meeting. The measure cleared the MOPC’s two-thirds approval threshold at 73.44%, evidence of transmission customers’ pushback over their perception that the process lacks transparency and does not treat all loads equally. The revision request relies on a “facilitating transmission owner,” determined yearly by the network customer with the largest load, scheduling an open meeting with other TOs, transmission customers and firm-service customers to establish the zonal planning criteria or any changes to it.

Golden Spread Electric Cooperative’s Mike Wise, SPC vice chair, said he felt the criteria’s language fell short as he shared with the committee the concerns of transmission-dependent utilities.

“The wholesale customers within the zones really wanted a collaborative process to be at the table,” he said. “Secondly, they understood there would be no cram-downs by the TOs. They hate it. They’ve lived with it for 60 years. We have to ensure all loads within a zone are treated equally and affiliates would not be favored through local criteria.”

American Electric Power’s Richard Ross said the idea that all loads will be treated equally would be the easiest “to scratch off the list as being nonexistent.”

“There will be one, singular policy that applies across the zone,” he said. “You’ll have the RTO applying that policy equally. It does require a collaborative process. At the end of day, someone has to make a decision if there’s not 100% agreement. We just need some experience with it. If people are not happy with it, we can revisit it.”

SPP Engineering Vice President Antoine Lucas said staff have been working to determine what “consensus-building” means in the context of local planning criteria.

“We came to the conclusion from staff’s role of facilitating the overall process that, within the zones, it’s probably more appropriate that they work together to define their view of consensus, or what levels of agreement are appropriate for moving forward,” Lucas said. “Does everyone have to agree with it? Maybe some voting structure needs to be put in place.”

SPC Adds New Members, Contracts with Facilitator

Barbara Sugg’s promotion to SPP’s CEO position and director Bruce Scherr’s recent passing has resulted in several changes in the SPC’s membership.

Bruce Rew, SPP senior vice president of operations, has replaced Sugg as the SPC’s staff secretary. Sugg, meanwhile, joins the committee as a member, while Director Susan Certoma replaces Scherr.

The committee has also entered into an agreement with an outside consultant to help facilitate and guide its future discussions. Strategic Offsites Group, a boutique Boston-based firm, was selected last month.

“We’re at a point now, with the way things are changing in the industry; we need to give it a fresh shot of thinking,” Altenbaumer said.

“We do not prescribe answers. I feel you have plenty of expertise in the organization,” Cary Greene, a partner with the firm, told the SPC. “Our job is not to tell you to go left or right, but to have a process in place where you decide what the strategies are.”

Greene said he expects to have a final strategic plan put together for the board in April 2021.

— Tom Kleckner

April 21, 2020February 18, 2025

Western Resource Adequacy Program in the Works

By Hudson Sangree

A resource adequacy program that could eventually encompass eight Western states and two Canadian provinces is being planned by the Northwest Power Pool (NWPP) to ensure sufficient capacity at a time of increasing retirements and shifts toward renewable energy in the West.

The retirement of fossil fuel plants, especially those fired by coal, and the variability of wind and solar resources means a shortfall could be coming starting later this year, NWPP President Frank Afranji said in a webinar Friday.

The footprint of Northwest Power Pool, in blue, covers eight states and two Canadian provinces. | NWPP

“Soon, areas in the West may face a capacity deficit of thousands of megawatts. Deficits of that magnitude may result in both extraordinary price volatility and unacceptable loss of load,” Afranji said in his presentation to the online meeting, hosted by the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body.

More than 2,000 MW of coal generation in the Pacific Northwest will go offline by 2023, and another 1,500 MW will retire by 2029, Afranji said in a recent article. Only four new natural gas plants totaling 1,100 MW have come online in the Northwest since 2011, and battery storage for renewable resources hasn’t reached the point where it can replace traditional generation, he said.

“The conclusion is that the Northwest is on track to face capacity shortages as soon as 2020, with a capacity deficit of thousands of megawatts by the mid-2020s,” Afranji wrote.

“The scale of this challenge led a broad coalition of Northwest utilities to work together to find solutions,” Afranji said in a related web post.

Last year, NWPP issued a report titled “Exploring a Resource Adequacy Program for the Pacific Northwest.” It noted that resource planning is largely performed by states and utilities, using different standards and methods, and that, as a result, “the region lacks insight into its overall resource situation.”

After the report’s publication in October, NWPP and 18 of its member utilities moved forward to design an RA program intended to improve reliability and lower costs. Members funding the program’s design phase include Avista, BC Hydro, NV Energy, Portland General Electric, Seattle City Light and Tacoma Power.

“The plan is to start with the 18 entities that are currently funding the program, which will cover the majority of the NWPP footprint, and once the program is up and running, cooperate with others that may be interested to join,” Afranji said in an email to RTO Insider. “We strongly believe in building this program in building-block type fashion. Once we have the first building block in place successfully, others will be invited to join or may request to join.”

NWPP has a total of 34 members, including major utilities such as the Bonneville Power Administration, PacifiCorp and Xcel Energy, along with smaller public utility districts. Its footprint covers British Columbia, Alberta and all the states in the Western Interconnection except California, Arizona and New Mexico.

The RA program is in a preliminary design phase with more detailed design work scheduled for the second half of 2020. The effort to implement the program is scheduled to start in 2021.

As outlined in Friday’s presentation, the RA program would include a “forward showing” component, in which entities would have to demonstrate they meet capacity requirements months in advance, and an “operational” component for short-term resource sharing.

NWPP member Avista Utilities, formerly Washington Water Power, owns the Monroe Street hydroelectric plant in downtown Spokane. | Visit Spokane

NWPP planners have been studying the work of CAISO and SPP, which have their own RA programs, Afranji said.

The NWPP program would be unique because it wouldn’t operate as part of an RTO or ISO, but it could still fall under FERC jurisdiction if it includes binding agreements, planners said. It would be voluntary to join, but once a utility joins, it will be contractually committed to the program’s requirements, they said.

A public webinar on the proposed program is scheduled for April 24. The RA section of NWPP’s website features videos and other materials related to the program.

Capacity Shortfalls Ahead?

Concern about Western RA has been a recurring theme during the past year, based largely on the replacement of fossil fuel generation with renewable resources. The number of states and local jurisdictions passing carbon-reduction requirements continues to grow and now includes California, Nevada and Washington, which have 100% clean energy mandates by midcentury.

Some are worried the difference between those goals and existing capacity will lead to shortfalls. Price spikes in the Pacific Northwest last spring left many questioning the region’s RA. (See NW Price Spike a ‘Wake-up Call,’ Ex-BPA Chief Says.)

CAISO and the California Public Utilities Commission have said capacity shortfalls could arise as soon as this summer and worsen next year. The state’s policy goals of increasing reliance on renewable energy resources while phasing out natural gas plants is behind the potential problem, CAISO and CPUC officials said. The planned closure in 2024 and 2025 of the state’s last nuclear generating station, Pacific Gas and Electric’s Diablo Canyon Power Plant, could worsen the situation, they said. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

In response, the CPUC ordered all load-serving entities under its oversight to collectively procure 3,300 MW of capacity, on a basis proportional to projected load, by August 2023. The CPUC voted in November to recommend that the State Water Resources Control Board allow four once-through-cooling gas plants built in the 1950s and 1960s to remain online even though they are the last of their kind and are slated to retire by the end of the year.

Concerns about a lack of coordination and oversight in Western markets have been raised in meetings of the Western Electric Coordinating Council. (See Western Reliability Margin is Thin, WECC Warns.)

A working group within WECC reported in February that the expected expansion of CAISO’s Western Energy Imbalance Market from a real-time only market to a day-ahead market will yield reliability benefits that could outweigh expected risks in the West. But those assurances haven’t done much to eliminate concerns. (See Study Gauges Reliability Benefits of EIM Day-ahead.)

WECC has an RA role, but it is more limited than that of the proposed program, NWPP said in its October report.

“Although both NERC and WECC publish information on resource adequacy planning, ensuring resource adequacy is the responsibility of utilities, state utility commissions, and other local and regional governing bodies,” it said.

Afranji said NWPP’s RA efforts will bolster WECC’s efforts.

“As to the WECC, this program will be complimentary to the RA activities they are engaged in,” he said. “The NWPP is part of WECC, and we have a great and symbiotic relation with them.”

April 20, 2020

CPUC OKs Largest Rollout of Covered Conductor

By Hudson Sangree

The California Public Utilities Commission on Thursday approved Southern California Edison’s ambitious plan to install nearly 600 miles of covered conductor to prevent its higher-voltage distribution lines from starting wildfires.

The move comes after devastating utility-sparked fires swept Northern and Southern California in 2017 and 2018, causing the state and utilities to rethink prevention efforts. (See California Regulators OK Utility Wildfire Plans.)

Covered conductor, with layers of insulation to protect it from sparking vegetation, is one of the main tools that utilities plan to use in fire-prone areas.

SCE’s Wildfire Covered Conductor Program would replace bare wires with insulated ones across a sizable slice of its service territory.

This “is the first large-scale deployment of covered conductor in California to harden the distribution system against extreme weather events and designed to reduce wildfire ignition events,” Administrative Law Judge Robert Haga wrote in a proposed decision that the commission adopted unanimously, without discussion, as one of the items on its consent agenda.

CPUC Covered Conductor — Covered conductor in Southern California is being installed on firberglass cross arms or in some cases using spacer cable. | *SCE*

In its ruling, the commission accepted a settlement between its Public Advocate’s Office, consumer groups and SCE, granting the utility more than $407 million for its Grid Safety and Resiliency Program, including nearly $285 million to install 592 circuit miles of covered conductor — representing about 6% of SCE’s primary distribution lines (typically rated at 12 to 16 kV) in high-risk fire areas.

SCE estimated a cost of $428,000 per circuit mile, including replacing wooden poles with stronger composite ones and installing fiberglass crossarms as needed.

High-voltage transmission lines have been blamed for sparking some of the worst fires in recent years, including the 2018 Camp Fire, the state’s deadliest and most-destructive blaze. A Pacific Gas and Electric line fell from a broken C-hook, igniting dry vegetation, state fire investigators found.

Distribution lines have been less prone to starting major fires. But SCE said that from 2015 to 2017, its distribution lines in high-risk regions sparked at least 132 fires large enough to report to the CPUC. The utility said 22 of the fires were started by lines contacting vegetation, more than any other identifiable cause.

“All else [being] equal, there was a relatively greater likelihood that a vegetation-related fault was ultimately associated with a fire event,” SCE said in written testimony to the CPUC in September 2018 that urged it to approve rate increases to fund its fire-prevention efforts, including covered conductor.

Covered Conductor Improves

SCE said the covered conductor now used is a big improvement over traditional tree wire that had one layer of low-density polyethylene insulation. Today’s wire, the new standard, has three layers: an outer coating of high-density polyethylene, an inner wrapping of cross-link polyethylene, and a semi-conducting sleeve wrapped around aluminum or copper wires.

The old covered conductor was heavy, required careful handling to avoid damage, and reduced load capacity because it heated up without the cooling properties of bare wire. It also was subject to degradation from the sun’s ultraviolet rays, SCE said.

The new insulated conductor is lighter but still weighs more than bare wire. It catches the wind because of its added bulk and needs stronger poles and cross arms. It also takes longer to install, said Brian Wilbur, electrical service manager with the Los Angeles Department of Water and Power.

Wilbur made his case in a separate meeting Wednesday of the CPUC’s Wildfire Safety Advisory Board, a group created last year to advise the commission’s new Wildfire Safety Division. (See California’s New Wildfire Board Holds First Meeting.)

Wilbur said LADWP is using covered conductor in high fire-risk areas.

“Covered conductors or tree wire is certainly nothing new to the industry,” Wilbur said. “But the advancement of the technology used today has made tree wire a viable solution in a lot of areas. The old tree wire that we used — that we’ve had in the systems for a long time — was heavy, required more robust construction techniques, had reduced loading capabilities and was very difficult to work with. Today’s tree wire is essentially a stronger construction material, and a lighter installation available on these conductors is becoming a great solution where other mitigating measures are not possible.”

Covered conductor is being used with along with vegetation management, composite poles, fiberglass crossarms and other measures, he told the board. The conductor adds an additional layer of safety, he said.

“One of the major things that we learned from the past wildfires is that even the most thorough vegetation management plan may not prevent branches from being blown into lines from an untrimmed palm tree on private property 50 feet away from our lines,” Wilbur said. “They can still dislodge, blow long distances and wreak havoc on our system.

“Covered conductors and resilient construction materials are critical in the high-fire-threat area to help prevent these hazards,” he said.

April 20, 2020March 12, 2025

PJM MIC Briefs: April 15, 2020

PJM’s Market Implementation Committee on Wednesday resumed its discussion on potential changes to how the RTO curtails generating output when needed to maintain stability during maintenance outages. Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units.

Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.

The MIC agreed in August to consider alternative approaches in response to a problem statement and issue charge by Panda Power Funds’ Bob O’Connell, who said PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.

PJM’s Keyur Patel gave a revised presentation Wednesday showing examples of how the RTO’s proposed approach would work. At the MIC’s March meeting, Paul Sotkiewicz, PJM’s former chief economist, said the examples in the RTO’s presentation contained errors in its LMP calculations. (See “PJM Developing Alternative on Stability-limited Generators,” PJM MIC Briefs: March 11, 2020.)

PJM’s proposed new approach for clearing stability-restricted generating units | PJM

PJM’s proposal is to model stability limits on generating units as a “capacity constraint” that doesn’t directly affect the LMP.

Sotkiewicz, now with E-Cubed Policy Associates, thanked PJM for correcting the examples but pressed the RTO on the need for the change.

PJM’s Joe Ciabattoni said the problem is when day-ahead commitments differ from those in real time.

“You could have a feasible solution in the day-ahead that’s infeasible in real time,” requiring operators to decommit one of the two units in PJM’s example and causing make-whole payments.

“We would prefer to have a solution that is feasible in both the day-ahead and real-time,” he said.

The discussion of alternatives to PJM’s proposal was cut short because the MIC meeting was running behind schedule.

ARR/FTR Market Task Force

PJM’s Dave Anders said the ARR FTR Market Task Force has completed three of its five key work activities (KWAs) in the issue charge approved by the MIC in October: reviewing the evolution of PJM’s auction revenue rights and financial transmission rights market design; reviewing congestion rights market designs of other regions; and discussing how PJM’s current design accomplishes its objectives.

The task force is currently discussing the “value proposition” of the market, the fourth KWA, and will soon begin the final one, proposal development, which it expects to run through August.

The initiative grew out of a recommendation in PJM’s independent consultant report on the GreenHat Energy FTR default that the RTO “conduct a general review of the FTR market … to evaluate the risks and rewards of potential structural reforms.”

The task force’s next meeting is April 29.

nGEM Project Update

PJM has decided to expedite the implementation of network applications for day-ahead and real-time markets under its Next Generation Markets (nGEM) project, a multiyear partnership among PJM, MISO, ISO-NE and General Electric that began in April 2017.

PJM’s Todd Keech said the day-ahead market clearing engine released by GE in March met all performance improvement criteria specified in the development contract.

GE and PJM last month completed factory acceptance testing for capacity and FTR data transfer improvements and network applications; a final GE release for those functions is expected in the second quarter.

Schedule for PJM’s Next Generation Market (nGEM) project | PJM

Keech said PJM is seeking to implement network applications for day-ahead and real-time markets in the fourth quarter to address findings from its “Markets Process Review.”

The Phase 2 nGEM agreement is under negotiation, he said.

The partnership with GE allowed the grid operators to share in development and maintenance costs and reduce time-to-market. PJM said the project will improve system security and quality.

Performance Assessment Interval Report

PJM is considering changes to its manuals and Tariff to address “a lack of clarity and detail” and improve the transparency of its performance assessment interval (PAI) settlements process, PJM’s Danielle Croop told the MIC.

Croop said the RTO will bring a problem statement and issue charge to an upcoming MIC meeting to address issues including ancillary service accounting and the determination of scheduled megawatts. It will also include provisions to make the language for energy-only and demand response resources parallel with that of generation resources, where applicable.

The initiative will seek to identify where more transparency or clarification is needed. “This effort is not intended to redefine any previously defined practices surrounding the calculation of performance assessment interval nonperformance assessments,” PJM said.

The average initial shortfall across the October 2019 performance assessment event was 10,457 MW, prior to excusals. | PJM

In March, PJM released a report on PAI settlements as an addendum to its r eview of the Oct. 1-2, 2019, performance assessment event, when an abnormal October heat wave led to emergency procedures and the first call on DR resources in more than five years.

The incident resulted in $8.2 million in nonperformance charges. Bonus payments averaged $32.89/MW-interval with the average bonus 9,706 MW/interval.

Independent Market Monitor Joe Bowring noted that the 2019 State of the Market report also includes an analysis of the October event. “We’re also working on a confidential report that we will share with PJM,” he said.

‘Quick Fix’ on PMA Credit Requirements

PJM’s Bridgid Cummings presented the MIC with a problem statement and issue charge for a proposed “quick fix” Tariff revision to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS).

The RTO requires load-serving entities to sign NITS agreements and post collateral based on their peak market activity (PMA).

In 2015, the Public Utilities Commission of Ohio moved NITS and other related charges to a non-bypassable rider that is the responsibility of the electric distribution company. The change means competitive retail electric suppliers serving load in Ohio are no longer allowed to collect NITS or any other transmission-related charges from end-use customers.

As a result, PJM’s credit requirements “do not reflect or consider the appropriate exposure for the responsible party” in Ohio, the problem statement says. “It is possible that other states may have similar laws in place or may enact similar laws in the future. This situation puts LSEs in those jurisdictions at a disadvantage with respect to having the responsibility for the applicable credit requirements in PJM although they have no responsibility for the underlying transmission service charges in the states in which they operate.”

As a result, PJM is proposing to amend Tariff Attachment Q to allow the RTO to adjust PMA requirements “where state law requires the transfer of charges or credits from a participant to another party.”

The committee will be asked to approve the issue charge and endorse the Tariff revisions at the May MIC meeting under the quick-fix process detailed in section 8.6.1 of Manual 34.

Regulation Market Settlement Agreement

PJM’s Eric Hsia gave a briefing on PJM’s compliance filing in response to FERC’s March 26 order approving settlements of two complaints over PJM’s regulation market design (ER19-1651-001).

The settlements resolved complaints filed in 2017 by the Energy Storage Association (EL17-64), and Invenergy and Renewable Energy Systems Americas (EL17-65), which alleged PJM’s January 2017 regulation market redesign violated commission precedent and discriminates against faster, dynamic “RegD” resources such as battery storage. (See FERC OKs PJM Regulation Deal over Monitor’s Opposition.)

– Rich Heidorn Jr.

April 20, 2020

Artificial Island Cost Dispute is Over — Almost

By Rich Heidorn Jr.

The long-running dispute over who pays for PJM’s first Order 1000 transmission project is finally nearing an end.

The $266.5 million Artificial Island stability project likely also generated millions in legal fees over the past six years, first in a fight over competitive bidding before PJM and later in an epic cost allocation saga before FERC.

On Thursday, FERC ended its refereeing in the cost allocation battle, rejecting a challenge to an April 2016 cost allocation order as moot because it was later reversed (ER15-2563). The commission also terminated docket EL15-95-002, saying rehearing requests in it have already been addressed in other dockets. Still pending is a petition filed by PPL Utilities in February asking the D.C. Circuit Court of Appeals to review three commission orders in the dispute.

PJM Artificial Island Cost — LS Power used helicopters for moving workers and materials during construction of the Artificial Island stability project. | *LS Power*

Meanwhile, the project, which includes a new transmission line between New Jersey and Delaware, is scheduled to be completed by the end of May. The project is designed to address stability limits on generation at the Salem and Hope Creek nuclear plants in New Jersey and transmission constraints that sometimes prevent the generators from exporting power at full capacity.

Stability vs. Power Flow

The original cost allocation would have assigned virtually all the costs of the project to Delaware and Maryland ratepayers, prompting state regulators to file a complaint alleging that the use of the solution-based distribution factor (DFAX) method was unjust and unreasonable when the benefit was system stability rather than power flow (EL15-95). In April 2016, the commission denied the complaint and accepted PJM’s proposed cost allocation (ER15-2563).

In July 2018, however, the commission reversed itself, finding the use of the solution-based DFAX unjust and unreasonable for stability-related reliability violations like that of Artificial Island. (See FERC: Stability Deviation Method Best for Artificial Island.)

On March 16, 2020, the commission accepted cost responsibility assignments for 20 baseline transmission projects, including reallocation of cost responsibility for Artificial Island based on the stability deviation method (ER20-736).

The commission’s Thursday order said that although it had initially accepted cost allocations using DFAX, the cost assignments never went into effect, rendering the rehearing requests in docket ER15-2563-002 moot.

“We’re excited about the end of the FERC process,” Sharon Segner, vice president of LS Power, said Monday. “It’s a big victory for Delaware consumers.”

LS Power won a share of the Artificial Island project after challenging PJM’s original award to Public Service Electric and Gas and promising to cap its cost at $146 million. Last month, FERC approved rules on how PJM will evaluate voluntary cost commitment proposals in the future. (See FERC OKs PJM Tx Cost Containment.)

LS Power Group’s Silver Run Electric is building a new substation in Delaware and a 5.5-mile, 230-kV transmission line, including a 3-mile crossing under the Delaware River, between the substation and the Hope Creek nuclear plant.

Nearly Done

The project, PJM’s first competitive solicitation under Order 1000, has a projected in-service date of June 1, according to PJM records.

“It’s nice when you’ve spent so much time on the policy side of Order 1000 seeing the fruits of LS Power’s work,” said Segner, who is a regular presence at PJM stakeholder meetings on transmission. She said FERC’s Standards of C onduct prevent her from sharing nonpublic, market-sensitive details about the status of the transmission construction.

LS Power is one of three companies building the project.

Delmarva Power is interconnecting the Silver Run substation with the existing 230-kV Red Lion-Cartanza and Red Lion-Cedar Creek lines for $2 million.

PSE&G is expanding its Hope Creek substation with a new 500/230-kV autotransformer and a new 500-kV bay for a combined $118.5 million.

Excluding the $51.5 million 500-kV bay at Hope Creek — which was allocated 50% based on load-ratio-share among 22 transmission zones, and 50% on the stability deviation method — the costs were allocated based on stability deviation among 10 transmission zones.

April 20, 2020

PJM Operating Committee Briefs: April 16, 2020

The winter of 2019/20 saw PJM with the lowest peak loads of the last seven years, as temperatures 4 to 6 degrees Fahrenheit above the long-term average kept energy consumption down.

Executive Director of System Operations Paul McGlynn told the Operating Committee on Thursday that the highest peak load was on Dec. 19 at slightly over 120,000 MWh, 10,000 MWh below the next lowest peak during the winter of 2015/16.

LMPs were very low all winter, McGlynn said, coming in at an average of $21.31/MWh compared to the next lowest recent number of $26.16/MWh in 2015/16. LMPs exceeded $100/MWh for only three hours over the winter.

PJM Operating Committee — Top 10 winter peaks by year | *PJM*

For the fourth straight year, natural gas was the primary fuel for generation, with a 38% share, compared to 35% for nuclear, 19% for coal and 7% for renewables. Natural gas overtook nuclear in 2016/17 as the most utilized winter fuel. Gas also passed coal that year as the most utilized fuel during winter daily peak hours.

The relatively mild winter, with few major snowstorms, led to only 12 emergency procedure events during the season, McGlynn said, the lowest total in the last six years. By comparison, PJM saw 43 emergency procedures in 2014/15.

“From an operational perspective, it was a fairly unremarkable winter,” McGlynn said.

Review of Operating Metrics

PJM’s Stephanie Monzon reviewed March’s operating metrics, highlighting that the balancing authority area control error limit (BAAL) performance has exceeded the 99% goal each month in 2020 so far, at 99.9%.

The BAAL standard was created to maintain stable interconnection frequency under normal and abnormal conditions to prevent instability, unplanned tripping of load or generation, or uncontrolled separation or cascading outages.

PJM compares the BAAL excursions in minutes to the total minutes within a month.

Monzon also pointed out the perfect dispatch performance score through March 2020 was 94.81%. Perfect dispatch refers to the hypothetical least production cost commitment and dispatch, achievable only if all system conditions, including load forecast, unit availability and transmission outages, were known and controllable in advance.

The perfect dispatch performance goal was designed to measure how well PJM commits combustion turbines in real-time operations compared to the calculated optimal CT commitment profile. Monzon said the perfect dispatch score has resulted in more than $21 million in savings in 2020.

Monzon said March was a “rather quiet operational month,” with three post-contingency local load relief warnings, four high system voltages and one heavy load voltage schedule action. One spinning event was recorded on March 8, Monzon said, which took place in the Mid-Atlantic Dominion region, lasting a total of five minutes, with a Tier 1 estimate of 1,541.4 MW and an actual response of 660.1 MW.

System Operations Subcommittee Report

PJM’s Rebecca Carroll gave a summary of the most recent System Operations Subcommittee meeting held April 13. Carroll highlighted four high system voltage actions in March, which are typically seen during periods of low loads. PJM will likely continue to see similar events in the upcoming months because of the impacts from the COVID-19 pandemic and the stay-at-home orders, she said.

Carroll said all weeks of the 2020 Operator Seminar have been canceled because of the pandemic. She said if operators need training hours to renew their certification, they should reach out to PJM at TrainingSupport@pjm.com.

While most offices remain closed, Carroll said the PSI testing c enter s, which administer tests required for PJM training, will reopen about May 1. Masks and gloves will be allowed for anyone going into the training center, she said.

Load Forecast Model Performance

PJM’s Elizabeth Anastasio provided an educational presentation on the performance of the RTO’s neural network machine learning algorithms, which identify the relationship between historical loads and temperatures to create load forecasts. It also considers cloud cover, humidity and the “effective” temperature, a measure similar to wind chill that takes into account wind speed.

What makes a good forecast model, Anastasio said, is a relatively low average error and a bias near 0%. She said bias is calculated by taking the average of hourly errors of over- and under-forecasting to determine the proportion between the two.

Although no model can predict all conditions, accurate models also have relatively few outliers of significant forecasting errors, Anastasio said. She said the best models also don’t see clear trends with outliers occurring at the same time of year or day.

Anastasio said PJM forecasters are constantly trying to assess how to improve load forecasting by looking back at past data as well as current conditions, analyzing outliers and investigating other forecasting methodologies and machine learning.

— Michael Yoder

April 20, 2020

EBA Holds Annual Meeting Online Successfully

By Michael Brooks

More than 300 energy industry professionals logged into a single video chatroom through Zoom on Wednesday to hear about the latest issues in energy law.

And — besides a half-hour delay while keynote speaker Gina McCarthy attempted to join, and other minor hiccups — the Energy Bar Association’s effort to hold its annual meeting through the internet because of the COVID-19 pandemic was a remarkable success.

In addition to McCarthy, CEO of the Natural Resources Defense Council and former EPA administrator, the event featured six panels on topics including notable ongoing litigation, FERC’s proposed revisions to how it enforces the Public Utility Regulatory Policies Act and landowner challenges of pipeline certificates. Discussions played out as they normally would at EBA’s conferences, usually held at the Renaissance Hotel in downtown D.C., except that panelists spoke from their home offices, living rooms or kitchens. Sometimes, they forgot to unmute themselves before they began speaking.

Meanwhile, attendees commented on the discussions in the text chat sidebar, though this was often limited to remarking on speakers’ impressive libraries or their use of Zoom’s prerendered backgrounds.

EBA Annual Meeting — NRECA CEO James Matheson addresses EBA annual meeting attendees, held through Zoom, in a panel on utility responses to the COVID-19 pandemic. Matheson is not seen because he joined the meeting by phone. EEI’s Emily Fisher moderated the panel. | *EBA*

The normally two-day event was compressed into one eight-hour marathon, made further compact by McCarthy’s delay and by shortening or even scrapping scheduled networking breaks, in which attendees were divided into separate, smaller chat rooms based on their sector or expertise.

The only breakdown in the meeting came during what is normally the luncheon awards presentation, in which members confirm incoming officers and board members by a ceremonial voice vote. In a physical setting, attendees need only pause between bites of their lunch to shout “aye” in response.

To replicate this experience, EBA attempted to unmute about 300 attendees simultaneously, wrongly assuming that everyone had returned from their lunch break and was paying attention. Robert Fleishman, presiding over the ceremony, was quickly drowned out as “a cacophony” — as one unknown attendee could be heard saying — flooded into the chat room: conversations, TVs, dogs barking.

Everyone was quickly muted again, and Fleishman asked if there were any “ayes.” Those that were paying attention to the proceeding unmuted themselves to respond.

“We don’t all speak with one voice clearly,” outgoing EBA President Jonathan Schneider said, laughing. “But on this election, I think we’ve got the message.”

At the end of the day, as EBA officials began breaking out the drinks to celebrate the meeting’s conclusion, many attendees voiced their appreciation, both through video and text, saying that it had brought some normalcy in a chaotic period.

Industry CEOs Laud Workers; Frustrated with Feds

After the awards ceremony, the CEOs of three major utility associations assured attendees that their members are working effectively despite the unique challenges posed by the pandemic.

Joy Ditto, Thomas Kuhn and James Matheson — the chief executives of the American Public Power Association, Edison Electric Institute and the National Rural Electric Cooperative Association, respectively — each said that reliability has not been impacted, despite extensive social distancing measures taken by line workers and a shortage of personal protective equipment (PPE). And each praised these workers as “real heroes,” asking attendees to keep them in their thoughts along with other essential workers.

Kuhn noted the severe weather over the Easter weekend on the East Coast, with tornadoes in the Southeastern U.S. and an ice storm in Maine.

“We had to figure out a new way to do business with respect to the pandemic,” Kuhn said. “We had to assemble crews” but keep one person per truck. Rather than house crews in trailers sitting in parking lots, “we had to find separate rooms in separate areas so we could operate.”

“But we did a fantastic job. This sector … is used to dealing with disasters and coming together and adapting,” he said. “I think we start way, way ahead of every other industry.”

Ditto also reported that mutual aid was occurring between APPA members as well as with EEI and NRECA members. She said an outbreak of tornadoes in Tennessee in early March, just before widespread economic shutdowns began in response to the pandemic, provided an early opportunity for utilities to learn how to work together while following social distancing and hygiene guidelines. The lessons learned during this event were implemented successfully when another tornado shredded Jonesboro, Ark., later that month, she said.

“Given the panoply of issues we face on a daily basis, we still had to learn some things as we’ve gone along in response to COVID-19,” Ditto said. But “the response is occurring. The mutual aid is happening.”

“To watch the participation across the different” utilities — investor-owned, municipal and cooperatives — was heartening, Matheson said. “Mutual assistance is one of the best calling cards we got in terms of how we’re committed to keeping the lights on.”

But, all three expressed frustration over shortages of PPE and testing.

Kuhn said EEI was having calls twice daily with the Department of Homeland Security, the Department of Energy and the White House, “but we weren’t able to break through” to them. “We were essentially behind the health care industry — which was obviously appropriate, because they were on the front lines — but what it meant to us was we were not getting the PPEs and not getting the testing.”

Finally, EEI was able to get in touch with the assistant secretary for health, Adm. Brian Giroir, whom Kuhn said understood the situation. “So that’s begun to break, and it’s been terrific,” he said, adding much more will be needed in time for summer.

“This is reflective of a broader national problem, and that’s not the topic of discussion today,” Matheson said. “But, you know, we’re behind on test kits — one could argue we should have been cranking up production test kits a long time ago — so we have a shortage of nationwide kits anyway.

“And for our sector, it becomes really important when you talk about certain critical employees. If you really want to keep the power plants running and keep the right people in the control rooms, you can’t just take someone from one power plant and stick them over in another one to replace someone who got sick,” he continued. “There are unique dynamics to every control room and every power plant. So it’s really important for these key employees that we have the capacity to … be able to test them on a regular basis.

“It seems pretty straightforward, but this has been a point of, quite candidly, frustration in terms of getting appropriate access to testing kits,” he said. “I think things are moving in a better direction, but I don’t want to say this issue’s resolved. This is still a big concern for my membership.”

Ditto echoed Kuhn’s and Matheson’s frustrations, but she added that utilities are getting creative with social distancing to ensure “that the most critical workers can continue to work even without testing.”

Several public utilities, including APPA member New York Power Authority, have sequestered their workers in control rooms in 30-day shifts, she said. In other cases, APPA has provided mobile homes for workers to live in. So far, workers have been receptive to the measures, as it protects their families and the public, she said.

“But it’s not ideal,” Ditto said. “It certainly puts more risk on our system than we’d like to bear and surely that the American public would like to bear.”

Matheson said that although he is not aware of any co-ops sequestering, some have gone as far as buying laundry machines just in case.

Financial Concerns Linger

The three CEOs also expressed their worries about the future viability of their members, who have pledged not to charge late fees or disconnect customers for nonpayment — or been barred from doing so by their states’ governors. All are lobbying Congress for long-term support in the inevitable future stimulus packages passed in response to the pandemic.

In the short term, the CEOs said, the focus has been on customers, many of whom are out of work and in desperate need of cash. Kuhn said that for the CARES Act, EEI pushed for increased funding in the Low Income Home Energy Assistance Program, which ended up getting $900 million.

As publicly owned utilities, APPA and NRECA members must return any surplus funds to ratepayers.

“A number of our members have adopted a policy to accelerate the return of revenue back to consumers … to get money into people’s pockets more quickly than would have otherwise happened,” Matheson said.

But the combination of nonpayments and lack of commercial and industrial demand “creates an economic hardship across the utility sector,” he said. “As the next stimulus package moves through Congress, it’s a sector that merits some attention. … In our case, this is about keeping the lights on, and I think it’s a pretty compelling argument.”

The CEOs also echoed arguments they have made in letters to federal officials. (See Co-ops, Public Power Seek US Aid in Pandemic.)

But Matheson also said that even before the pandemic, he had been flustered by a lack of funds from the Federal Emergency Management Agency. Despite having approved cost reimbursement for storms in 2018, “FEMA has never given them the money,” Matheson said. “Those are co-ops that are holding all that expense they did for storm repair on a line of credit and are paying interest on it now. And if they were able to receive their already-approved FEMA reimbursement, that would certainly be a benefit for them” getting through the pandemic.

Ditto said APPA is considering asking for short-term “bridge loans to enable some of our members to get past this squeeze.”

A Post-pandemic Future

The CEOs were asked how they thought the energy industry would change once the U.S. gets through the pandemic and things return to normal.

Matheson said that businesses may realize it is more cost effective for their employees to work from home, at least for part of the work week.

But he and Ditto noted that the pandemic has highlighted that many of their customers still lack access to broadband internet. They both hoped that the crisis would spur federal investment in broadband infrastructure in the rural U.S.

All three CEOs agreed that, at least in the short term, investment in clean energy resources would pause.

When society does start to go back to normal, Ditto concluded, “I’m very optimistic that we can … go back to work while still ensuring that we stay healthy. I think if we just do it systematically, we’re going to be OK.”

Kuhn said that many are noticing that the air has been cleaner since they began sheltering in place. He speculated that this may accelerate electrification of the transportation sector.

NRDC’s McCarthy also mentioned the reduced emissions in her keynote speech. She said that cable news show hosts always note the substantial reduction in emissions as a result of the pandemic when she’s a guest. “They turn it over to me and seem to think I’m going to go, ‘Wow, isn’t this great?’” she said incredulously. “That’s not how I want to succeed!”

But, she said, “maybe these times are giving us a sense of the importance of science.”

April 20, 2020

PJM, IMM at Odds on 5-Minute Dispatch, Pricing Rules

By Rich Heidorn Jr.

PJM backed off plans to seek a vote next month on short-term changes to its five-minute dispatch and pricing procedures after pushback from the Independent Market Monitor and stakeholders.

PJM’s Tim Horger told the Market Implementation Committee on Wednesday that the RTO was prepared to make manual changes detailing short-term changes but needs more time to evaluate the operational benefits and impacts of long-term changes it has been discussing with the Monitor.

Horger said the short-term changes comply with FERC Stalls PJM Fast-start Compliance Filing.)

The commission ordered PJM and NYISO a year ago to revise their tariffs to allow fast-start resources to set clearing prices. (See FERC Orders Fast-start Rules for NYISO, PJM.)

PJM’s proposed short-term fixes would align the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 using the RT SCED solution for a 12 p.m. target time.

PJM Dispatch Pricing rules — Proposed short-term implementation | *PJM*

The RTO would execute LPC cases every five minutes after the start of a dispatch interval, using as inputs resource offers, parameters and ancillary service assignments for the interval ending at the target dispatch time. Offers for 11 to 12 would be effective up to and including the 12 p.m. target; offers for 12 to 1 p.m. would be applied to a dispatch target of 12:05.

Horger said PJM also has committed to conduct operator training and make software changes to limit automatic execution of RT SCED cases to once for every five-minute target time. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.

The long-term changes would include auto-execution of RT SCED cases every five minutes with a target time of 10 minutes into the future.

If dispatchers do not manually approve an RT SCED case for a target time, a case would be automatically approved before the start of the dispatch interval. It would also add transparency when cases are not approved for a target time because of data errors or software failures.

Horger said PJM wants to prioritize and consider parallel or incremental implementation of the long-term changes. “It might look good on paper, but until we get a comfort level on an operational level, we can’t commit to it.”

IMM Joe Bowring said the Monitor thought it had reached an agreement with PJM following “months of productive discussions” on a compromise that would give dispatchers better information closer to the dispatch time and help ensure consistency between dispatch and pricing.

But he said the RTO posted a presentation and a proposal matrix the night before the meeting that indicated the RTO no longer supported the agreement. The RTO’s current long-term proposal “is vague at best and probably years away,” he said.

In addition to aligning pricing and dispatch, Bowring said in an email later, it also is essential to reduce “the RT SCED dispatch interval from 10 minutes to five minutes, running RT SCED on a regular five-minute interval to match the pricing interval to minimize running multiple RT SCED cases and changing dispatch instructions for the same target time, and using the prior RT SCED case as inputs to the current RT SCED case.”

“Our goal continues to be a single comprehensive package,” he said at the meeting. “We believe the entire package is needed to make SCED and LPC work consistent with the FERC order … and it’s really required for fast-start pricing to work correctly.”

“This is something were going to need to test. It requires operator training,” responded Horger. “It won’t be years away. It will be a lot closer than that.”

PJM says the long-term changes may require a revised approach to ancillary service products.

“If we slow down the dispatch, [our concern is] what other compensating measures we [might] need to take,” explained Adam Keech, PJM vice president of market services. “Do we need more regulation if we slow down the dispatch? Sitting here today, I don’t know that we know the answer to that.”

Bowring noted that PJM recently changed the automated case execution for SCED from three to four minutes without operator training. “I don’t know why training is needed to go from four to five minutes,” he said.

Keech said the RTO believes the intermediate and long-term changes aren’t required by the FERC order because they are not used “uniformly” in other RTOs/ISOs. He acknowledged that the recent change in the automated SCED case execution from three to four minutes has not caused any operational issues.

But he said that shift still allowed dispatchers to manually order additional cases in response to changing conditions. Preventing dispatchers from such manual intervention “is much different than where we are today,” he said. “TBD on an exact timeline, but I will say there is motivation to make the change quickly, but I will add, judiciously.”

Keech also said PJM’s long-term goal is to greatly reduce dispatchers’ interventions while retaining operators’ ability to approve SCED cases if, for example, they unexpectedly lose a large generating unit. “The desire is not to [intervene] unless it’s absolutely necessary.”

He said about one-third of approved RT SCED cases do not set prices currently because they are supplanted by new cases.

One stakeholder representing a trading firm who said he was not permitted by his company to be quoted by name said PJM’s current practices are preventing proper transient shortage pricing even when the system is in a “critical state.”

He cited a spinning reserve event in February that resulted from an under-forecast for load, an incident in October in which load rose faster than forecast and a July 2018 time error correction at noon and subsequent unit trips that resulted in a drop in system frequency on the Eastern Interconnection.

MIC Chair Lisa Morelli concluded the discussion by saying the committee will hold a second first read of the proposal in May. “I think it’s pretty apparent we’re not ready to move this to a vote at the next meeting,” she said.

In the interim, the MIC will hold a special meeting on the issue May 1.

Horger said that because the short-term changes only affect the manual and do not require FERC approval, the delay should not prevent the RTO from making the changes by July as planned.

April 20, 2020

PJM PC/TEAC Briefs: April 14, 2020

RTMEP Process Ready to Move Ahead

PJM told the Planning Committee on April 14 that it is standing behind its intention to seek stakeholder approval of a new regional targeted market efficiency project (RTMEP) process without first developing cost allocation rules.

PJM attorney Pauline Foley reiterated her statements from the committee’s March 10 meeting, saying LS Power Challenges PJM on MEP, SATA.)

LS Power’s Sharon Segner acknowledged that cost allocation is the TOs’ responsibility, but she said FERC Order 1000 requires any regional planning process to be accompanied by a cost allocation methodology. Segner reviewed a legal memo filed by LS Power regarding cost allocation for the new project category.

Foley said she agreed with LS Power’s contention on the importance to know the cost allocation methodology before PJM designates a project or implements a planning process. But she disagreed with the memo’s contention that a methodology must be simultaneously filed with the planning process. “I don’t see anything in Order 1000 that says that,” she said.

PJM officials noted that stakeholders have been working on the issue for at least 18 months and said that if it’s pushed back any further, it could prevent implementation before 2022. PJM stated it is prepared to seek a vote on a new measure at the May PC meeting.

Alex Stern of Public Service Electric and Gas provided a response from the TOs regarding the LS Power memo. He said the plans that have been proposed follow existing transmission planning principles and comply with Order 1000.

“Once we have an effective [stakeholder-approved] package, the TOs will begin developing any needed cost allocation revisions that emerge,” Stern said. “This is consistent with the transmission planning approach that has been followed in the past.”

Segner said there remains a “long path ahead” on the RTMEP process for stakeholders. She said there has been no consensus on the proposals submitted thus far.

“The members deserve to know the cost allocation methodology for an entirely new type of regionally planned project category,” Segner said. “If FERC can’t accept these filings without understanding what the cost allocation methodology is going to be, why should the members? Why is it that the members are considering approving changes without knowing what the cost allocation framework is going to be?”

Competitive Planner Nears Debut

Ilyana Dropkin of PJM presented an update on the Competitive Planner, a new web-based application for TOs and developers to participate in the RTO’s competitive planning process under Order 1000.

By publishing a set of criteria violations and soliciting solutions from competing developers in the new application, Dropkin said, PJM and FERC are hoping to encourage innovative and cost-effective solutions for transmission needs.

Dropkin said that having a web-based application increases the speed and accuracy of the process and provides near-real-time tracking of submissions.

Anyone looking to participate in PJM’s competitive planning process can get access to Competitive Planner by prequalifying through the critical energy/electric infrastructure information (CEII) process, Dropkin said.

Training for the application is expected to be available on May 6, Dropkin said, and the full implementation of Competitive Planner is expected by June 24.

Transmission Expansion Advisory Committee

Deactivation Notifications

Phil Yum of PJM provided the Transmission Expansion Advisory Committee an update on two recent generation deactivation notifications.

The first highlighted was PPL’s Keystone NUG, a 4.9-MW coal-fired unit scheduled to retire on May 31. Yum said PJM determined during analysis that no violation was identified with the unit’s closure.

Generation deactivations for 2018-2020 | *PJM*

Second, Chesterfield Units 5 and 6, producing 1,015 MW in the Dominion zone, are scheduled to retire on May 31, 2023. Yum said a generation deliverability problem was discovered at the Chickahominy 500/230-kV transformer that was overloaded for loss of the Chickahominy-Surry 500-kV line.

Yum said PJM is recommending installing a second Chickahominy 500/230-kV transformer at an estimated cost of $22 million.

PJM: Error had no Impact on Project Selection

PJM’s Brian Chmielewski told the TEAC that FirstEnergy’s admission that it included an incorrect winter-normal rating in its proposed rebuild of the 115-kV Hunterstown-Lincoln line did not affect the RTO’s selection of the project (HL_622).

PJM selected the $7 million proposal by FirstEnergy’s Mid-Atlantic Interstate Transmission (MAIT) subsidiary as the solution for the Hunterstown-Lincoln congestion driver following the 2018/19 long-term window.

After MAIT told PJM of the error on March 6, the RTO’s market efficiency unit reran the proposal with the updated rating, Chmielewski said. “There was no change to the congestion or dispatch when that rating was updated,” he said, adding that PJM stands by its decision.

In February, Ameren asked PJM to reconsider its selection of the project over 22 other proposals, including the company’s proposal for installing a SmartWires SmartValve. (See PJM Rejects Ameren Challenge on Tx Project.)

RTEP Window Delayed

PJM’s Aaron Berner said delays in the development of Regional Transmission Expansion Plan cases have pushed its schedule back by three weeks. Posting of preliminary violations, originally targeted for April 15, is now expected on May 8. The opening of the 60-day proposal window, originally expected June 1, is now set for June 24.

Supplemental Project

Paul Mills of Commonwealth Edison presented needs and a solution for several supplemental projects, including the Lisle 345/138-kV Transformer No. 83 that acoustic testing showed higher-than-expected vibration levels and increased frequencies associated with looseness in the core/coil assembly. The solution calls for replacing the transformer and adding a high-side circuit breaker at a cost of $8.5 million.

— Michael Yoder

April 20, 2020

PJM Eyeing New Black Start Changes

By Michael Yoder

While PJM’s controversial initiative to tighten fuel requirements for black start resources is on pause, the RTO said last week it wants to clarify and update its documentation on the substitution and termination of those resources.

PJM’s David Kimmel presented a first read of a proposed problem statement and issue charge at the Operating Committee meeting Thursday, saying PJM officials have identified four areas in the Tariff and manuals in need of updates.

Last month, PJM suspended its initiative looking at black start fuel requirements, which faced opposition from state regulators and consumer advocates. (See PJM Backs off Black Start Fuel Rule.)

Kimmel said while the fuel requirements initiative remains on “hiatus,” the RTO wanted to clean up black start resource language in the Tariff not related to fuel.

“We have received a lot of questions on substitution, and we wanted to make those rules more clear,” Kimmel said.

PJM is first rewriting language for testing requirements for black start resources not compensated through Schedule 6A of the Tariff. Kimmel said PJM has identified the need to provide clarity within testing requirements to ensure consistency, including test submittal timelines, for black start units compensated by either PJM or transmission owners.

PJM Black Start — Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start capable unit. Calpine acquired Tasley in 2010 as part of its purchase of the Conectiv Energy assets. | *Calpine*

Kimmel said the black start units in PJM are typically compensated through Schedule 6A, while some units entered service through a contract with a TO that was integrated into the system. In order to receive compensation, the unit must submit a successful black start test to PJM every 13 months.

The second clarification PJM is seeking is on black start unit substitution rules. Currently the Tariff allows a black start unit owner to substitute another unit as long as it’s on the same voltage level and has a valid annual black start test.

Kimmel said PJM has received increased questions on adding, maintaining and managing units as black start substitutes. He said some of the questions that have been raised include the notification time required to allow a substitution and how to manage updates to system restoration plans documenting black start resources.

Black start termination rules are also being addressed, Kimmel said, to address potential delays in planning and replacement.

PJM and black start unit owners are currently required to provide a one-year advance notice of intent to terminate service. Kimmel said that could allow a unit to remain in the system without a successful test on file for an extended period of time before being terminated, delaying PJM from procuring a replacement.

The RTO also is looking to update the black start capital recovery factor (CRF) table in the Tariff to reflect current tax law and interest rates. It also is exploring a new process for automatically updating and documenting the table to remain current.

Kimmel said black start units electing to recover new or additional capital costs must commit to provide black start service for a term based on the age of the unit, and the CRF table lists the term periods of commitment and applicable capital cost recovery factors. He said recent tax law and interest rate changes don’t reflect the assumptions used in the current CRF and need to be updated.

Work on the proposed changes is expected to take two to three months, Kimmel said, and it could be another six months before the changes would take effect in the Tariff. Changes are also anticipated to Manuals 10, 12 and 14D.

Process Questions

Independent Market Monitor Joe Bowring said he agreed with PJM’s proposal that the CFR table needs to be modified for tax law changes. He recommended that a reference interest rate be used as part of the problem statement and issue charge for the new changes and that the Moody’s Utility Index for bonds already in use in the Tariff for black start-related matters be the benchmark.

Bowring also said he would also like to see the black start minimum tank suction level (MTSL) issue addressed in the new changes. He said the MTSL has been an issue for several years that has not been clearly addressed. PJM had agreed with the Monitor’s position and had included such an agreement in the black start fuel requirement initiative that is now on hiatus, he noted. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)

PJM’s Tom Hauske said the MTSL is still part of an active stakeholder process with the fuel resource initiative and should remain there.

“We’re not sure that you can pull something from one stakeholder process and then bring it over into a whole other stakeholder process,” Hauske said.

Bowring said he didn’t see why the MTSL issue couldn’t be addressed in the new process, as the fuel cost committee is currently on hiatus. Bowring also pointed out that the CRF table was part of the fuel assurance matrix being discussed in the black start fuel requirement.

Hauske said the previous fuel assurance matrix discussion dealt only for new units that were going to provide fuel assurance and did not apply to current units that were switching to black start, which is what the new proposed changes are meant to answer.