At its quarterly meeting Tuesday, NERC’s Operating Reliability Subcommittee decided to cut back its weekly schedule of conference calls focused on the COVID-19 outbreak. Calls planned for this week and May 13 were canceled, and the team agreed to move to biweekly discussions following the next scheduled call on May 20.
ORS Chair Chris Pilong, of PJM, suggested the coronavirus meetings could be scaled back — though not eliminated entirely — because registered entities have largely settled into their pandemic response plans and there are “enough other calls going on between companies that we don’t need to hold the pandemic call” as frequently. Future calls to discuss new developments will be held every other Wednesday at 2 p.m.
GSE Communications Plan Nearing Completion
The group developing communications procedures to be used during a grid security emergency (GSE) is preparing to finalize its recommendations and hand them off to NERC for implementation.
The GSE Communications Project was created last year based on the North American Transmission Forum’s (NATF) work implementing the 2015 Federal Power Act, which enables the Energy Secretary to determine if emergency measures are necessary upon presidential declaration of a GSE. Such declarations are available in the case of physical, cyber or electromagnetic pulse attacks or in the case of geomagnetic disturbances. They are not permitted in response to natural disasters.
Efforts by the GSE communications team have focused on leveraging existing communications protocols used to share strategic and long-term goals between the Department of Energy and reliability coordinators (RCs). Their plan is to expand these pathways to share shorter-term operational communications as well, through avenues with which both participants are already familiar.
“We’re trying not to introduce new things,” said Lynna Estep of NATF. “We want to use the RC hotline as much as possible [and] we want to use the RC emergency conference call processes, but just tailor [them] for GSE … We’re not trying to change any of that, we’re just trying to add a layer [to] make sure we have what we need for the DOE to communicate to us during this very specific type of event.”
ORS members asked the development team to make sure their outline provides a realistic role for both the government and RCs. In particular, John Norden of ISO–NE reminded the team to factor in the response time of RCs and not create expectations that they will “turn around and just execute” government instructions. In response, Sam Chanoski, director of threat intelligence for the Electricity Information Sharing and Analysis Center, noted that the development team is “ahead of where the government is” and can hopefully lead the way in setting expectations.
The GSE elements of the Federal Power Act have not yet been exercised, and Estep emphasized that her team is focused on ensuring the grid is not caught unprepared the first time. She pointed to the ongoing pandemic to illustrate the benefits of ensuring preparedness.
“I was on a call earlier today, and as many calls today go, it [went] to COVID-19. And one of the comments made was [that] if we hadn’t had some pandemic plans made ahead of time, then we would have been in a really bad place,” she said. “I see this being the same way … It may not be absolutely perfect, especially because we’re working with some unknowns here, but we need to have something in place.”
ORS, SMS, Could Merge in RSTC Reorganization
The COVID-19 outbreak has complicated the introduction of NERC’s new Reliability and Security Technical Committee (RSTC), but the group still plans to take over the operations of the Planning, Operating and Critical Infrastructure Protection Committees as scheduled in June. The committee’s June 10 meeting, which was planned to take place at NERC headquarters in Atlanta, has now been changed to a webinar in accordance with the organization’s coronavirus response policy. (See “Robb Delivers COVID-19 Update,” Align Tool Set for 2021 Rollout.)
Since its first official meeting in March, the RSTC has been holding weekly conference calls to bring its members up to speed on the work of the retiring committees. (See RSTC Tackles Organization Issues in First Meeting.) Leadership felt this was necessary to ensure that important matters are not lost in the transition to a smaller structure.
“Right now we’re in the process of reviewing the existing subgroup organization and work plans … to ensure continuity from the technical committees to the RSTC,” said Stephen Crutchfield of NERC. “We have a few people on the RSTC that were not on any of the technical committees before, so this is to make sure that they’re aware of things that come up on a routine basis.”
The committee has also been ironing out details of how RSTC meetings will be structured, as well as how to take reports from the existing committees’ various subcommittees and working groups without overwhelming the agenda in routine items.
While most subcommittees are expected to continue their work as usual, reporting directly to the RSTC instead of their previous committees, leaders of the Synchronized Measurement Subcommittee (SMS), presently under the Planning Committee, are currently in talks to merge their group with the ORS. SMS Vice Chair Tim Fritch said the idea was inspired by his group’s recent work helping to analyze outage events, which leadership saw as an indication that it could be more helpful on the operational side than in a planning role.
“It seems like there’s more efficiencies and effectiveness with us being more tied in to the ORS, and we can help more with these events that we’ve seen. We know there will be more coming forward as we have more data and more devices to monitor the system,” he said.
FERC last week approved penalty settlements for violations of NERC standards by Mississippi Delta Energy Agency (MDEA) and the Western Area Power Administration’s Rocky Mountain Region, along with an unnamed utility in the Eastern Interconnection. The violations carry penalties of $70,000 and $225,000 for MDEA and the unnamed entity, respectively.
WAPA’s Rocky Mountain region — which manages a control area in Loveland, Colo., known as Western Area Power Administration, Colorado Missouri (WACM) — is not subject to monetary penalties because of a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal entities.
NERC submitted the settlements to the commission March 31, filing separate Notices of Penalty for MDEA and WACM and a spreadsheet NOP for the other utility noting that its settlement with ReliabilityFirst covered 16 violations. In a notice on Thursday, FERC said it would not review the penalties, leaving them intact.
CIP Update Falters for Unnamed Entity
ReliabilityFirst’s settlement with the registered entity — which was not identified in the spreadsheet NOP under NERC’s policies regarding security risks to critical electric infrastructure — relates to violations of critical infrastructure protection (CIP) standards. ReliabilityFirst said the deal “arises out of the entity’s efforts to improve and advance its approach to CIP compliance after identifying several issues related to its transition to CIP Version 5.”
The spreadsheet NOP identified one violation each of CIP-002-5 (categorizing bulk electric system cyber systems and associated assets commensurate with the adverse impact of their loss, compromise or misuse); CIP-004-3a (training requirements for personnel having authorized cyber or authorized unescorted physical access to critical cyber asset); and CIP-007-3a (securing systems determined to be critical cyber assets and non-critical cyber assets within the electronic security perimeter); three for CIP-010-2 (preventing and detecting unauthorized changes to BES cyber systems by specifying configuration change management and vulnerability assessment requirements); and 10 violations of CIP-007-6 (managing system security by specifying select technical, operational and procedural requirements in support of protecting BES cyber systems against compromise).
According to ReliabilityFirst’s analysis, the issues arose when the utility sought to update its systems to address problems identified in a previous settlement with the regional entity; the utility believed that it could fix these deficiencies by adopting new tools to automate multiple tasks.
However, the utility was “not adequately prepared to deploy these new tools and processes effectively,” ReliabilityFirst said, and, as a result, the entity failed to properly configure assets and tools prior to deployment, ensure that staff members were appropriately trained to manage them, or ensure that processes were in place to support their implementation and operation. This failure led to a number of violations that the entity self-reported in 2017-2019.
Linemen climbing a WAPA tower in California | WAPA
In its settlement, ReliabilityFirst cited the utility’s internal compliance program as a mitigating factor in the penalty determination, observing that more than 90% of the entity’s noncompliance since 2012 has been self-reported, and that the average amount of time between the beginning of a noncompliance and the entity reporting it has decreased significantly over the same period. The RE also said that the entity has made improvements in recent years that “have positively impacted the compliance culture in the CIP program,” such as organizational changes and hiring new personnel to address critical skill deficiencies.
On the other hand, the RE cited previous violations involving the utility (redacted from the public filing) to justify aggravating the monetary penalty with regard to two of the CIP-007-6 violations. ReliabilityFirst argued that the entity had failed to fully mitigate the prior violation, which justified a stiffer punishment.
Tree Violation Snags MDEA
MDEA’s $70,000 settlement with SERC Reliability arose from the violation of reliability standard FAC-003-4, governing the management of vegetation located on transmission rights of way, on its 230-kV Moon Lake line, a 23-mile facility connecting Entergy’s Moon Lake substation to the city of Clarksdale, Miss.
The utility discovered during an inspection in September 2017 that a willow tree had grown within the Moon Lake line’s minimum vegetation clearance distance, calculated by MDEA to begin 4 feet above the ground.
The tree’s growth had gone undetected because, while MDEA required monthly inspections of the line, the utility’s regulations permitted these inspections to be skipped as long as personnel noted the omission in their monthly logs and the line was inspected at least once every calendar year, with no more than 18 months between each inspection.
In the case of the line segment where the willow tree grew, inspectors had not visited it since Dec. 2, 2016. Based on average willow tree growth rates, MDEA estimated that the tree reached an unacceptable height on Feb. 15, 2017; as a result, the violation was determined to have begun on that date and ended with the tree’s removal on Oct. 6, 2017.
SERC determined that MDEA’s transmission vegetation management plan (TVMP), while technically compliant with NERC standards, was not sufficient to ensure that trees would not interfere with transmission lines. Specifically, the RE said the utility’s procedure, which allowed up to 18 months to pass between inspections, failed to account for fast-growing trees that could encroach on equipment within that time frame.
According to SERC, the violation “posed a serious and substantial risk” to bulk power system reliability, not just because of the danger of a contact of flashover event from the tree but also the deficiencies the incident revealed in MDEA’s vegetation policies. On the other hand, the RE noted that MDEA had promptly removed the offending tree after discovering it. It also cleared the additional vegetation that had prevented personnel from accessing the area in the first place, hence making future inspections easier.
In addition, the utility had self-reported the violation to SPP (its RE at the time) in December 2017 and has updated its TVMP to require the line be fully inspected every six months. MDEA also updated its training procedures to ensure that personnel responsible for implementing the TVMP are aware of these changes.
WECC Discovers Widespread Misratings
The settlement agreement between the Western Electricity Coordinating Council and WACM resulted from a violation of FAC-009-1, the reliability standard that previously governed methodologies for determining facility ratings (now replaced by FAC-008-3). Unlike the other settlements submitted by NERC, this violation was discovered by WECC during a compliance audit rather than via self-report. Although WACM did inform WECC in August 2018 that it had found evidence of a possible violation when it was preparing for the audit, the full extent of the problem was found by the RE itself.
In reviewing information from a sample of 10 transmission facilities, WECC determined that five of them showed discrepancies between the documented and actual facility ratings. Based on this information, the RE ordered a further investigation that revealed that of WACM’s 258 transmission facilities covered by the standard, 78 have actual facility ratings below those documented, while 180 are above or equal to documented ratings. Of 35 transformers applicable to the standard, 10 are below the documented ratings and 25 are at or above them.
WECC described the violation as a “serious and substantial risk to the reliability of the BPS” that could have led to equipment operating above appropriate ratings, possibly resulting in overloads and outages. The issue was also exceptionally longstanding, having begun when WACM was recognized by WECC as a transmission owner in 2007. The RE determined that the original violation was a result of the utility populating its initial FAC-009 documentation with historical ratings rather than properly verifying this information.
“The ratings process was inconsistently documented, as well as stored in multiple locations,” the NOP said. “In addition, a contributing cause was the lack of internal controls to ensure how the facility ratings had been documented was accurate and complete. … WACM not only established inaccurate facility ratings when FAC-009-1 R1 became enforceable, but carried forward those historical inaccurate ratings.”
WACM’s remediation and mitigation strategy requires it to review and verify equipment ratings for all elements in a facility rating, evaluate corrective action plans for all facilities with incorrect facility ratings and provide WECC with bimonthly project status reports. WECC acknowledged this action while noting that it has not been completed yet; the project has a proposed completion date of Dec. 15.
PJM’s Annual Meeting, which was to have been held Monday in Chicago, was canceled because of the coronavirus pandemic. But the RTO held its Members Committee meeting via teleconference nonetheless, feting Board Member Susan J. Riley and former Vice President of Planning Steve Herling on their retirements.
Riley Feted on Retirement
Riley, who took over as interim CEO after the tumultuous fallout of the GreenHat Energy default, was honored on her retirement from the RTO. The former CFO for Eastern Outfitters, Riley had served on the PJM Board of Managers since 2005.
Riley guided the organization after former CEO Andy Ott announced his retirement effective June 30, 2019, following an independent probe into the GreenHat debacle that concluded PJM staff ignored red flags about the company’s assets as it amassed 890 million MWh of financial transmission rights while putting up only $60,000 in collateral. (See PJM CEO Andy Ott to Retire.)
A certified public accountant, Riley served in senior finance roles for The Children’s Place, Abercrombie & Fitch, Mount Sinai Medical Center of New York, Colgate-Palmolive, Dial Corp. and Tambrands.
PJM Board member Susan Riley and Chair Ake Almgren | PJM
Riley said her work at PJM provided a unique experience because it gave her direct interaction with the RTO’s “constituents.” Understanding the diverse interests of PJM members was both a challenge and a pleasure, she said, adding she was impressed to see stakeholders working together to solve problems.
“The results of your hard work through compromise and member meetings is a system that delivers reliable and cost-effective electricity to over 65 million people day in and day out,” Riley said.
Members Committee Chair Steve Lieberman, director of regulatory affairs for American Municipal Power, said Riley’s listening skills, responsiveness to stakeholders and ability to make hard decisions illustrated “what a fantastic leader Sue is.”
Lieberman praised Riley for “taking ownership” following the GreenHat default, which he said was “not a shining moment for PJM.”
“She made it a personal issue to make sure that it would not, could not, occur again,” Lieberman said. “On behalf of PJM, she repeatedly owned up to the deficiencies of PJM. She took hard questions” from members. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)
Lieberman said he was equally impressed with Riley’s ability to step into the CEO role after Ott left. Several top PJM management personnel were out of their positions within a few months, and Lieberman said Riley was able to hold the RTO together until replacements could be found.
“The ground felt a little shaky from my perspective, but Sue figuratively took the reins and steered us through those uncertain times,” he said.
Board Chair Ake Almgren thanked Riley for her “many contributions to PJM.”
“Through all these years, I looked forward to Susan’s work ethic and her active leadership and very strong commitment to PJM,” Almgren said.
The Members Committee elected Margaret “Margo” Loebl to the Board of Managers, replacing Susan Riley, who retired. | Margaret “Margo” Loebl
The MC re-elected Almgren and member Charles Robinson, while selecting Margaret “Margo” Loebl, to replace Riley. Loebl, who has 30 years’ experience with Fortune 500 companies in finance, accounting and risk management, is the former CFO of AgroFresh Solutions, which provides technologies and services to extend the shelf life of fresh produce.
The board waived its term-limit policy for Almgren, who has been on the board since 2003, to allow him to serve an additional year to “ensure a successful leadership transition.” Since 2016, PJM rules have limited board members to five three-year terms.
PJM Sees Potential $26M Revenue Drop from Pandemic
PJM CFO Lisa Drauschak told members the RTO is planning for as much as a $26 million reduction (8.3%) in its Schedule 9 revenues because of reduced energy use during the coronavirus pandemic and is cutting expenses and lining up additional financing in response.
Schedule 9 revenues, which are collected based on transmission usage, represent 85% of PJM’s total income, Drauschak said.
The RTO collected $81 million in Schedule 9 revenue in the first quarter, and its budget anticipated an additional $231 million for the rest of the year, assuming 783 TWh of electric consumption.
But March load was 6.6% below budget and April is expected to be 7.5% below projections, reflecting both shelter-in-place orders and unusually warm weather.
Because of uncertainties over the length of the pandemic, PJM developed three scenarios for load:
Scenario A: 723 TWh, reflecting a 14.4% reduction through May before ramping up to normal, would reduce Schedule 9 revenue for the remainder of the year to $224 million.
Scenario B: 693 TWh, a 14.4% reduction through August before ramping up to normal, would produce $213 million in Schedule 9 revenue for the second through fourth quarters.
Scenario C: 670 TWh, a 14.4% reduction from the total for the year, would generate only $205 million in additional revenue, an overall reduction of $26 million (8.3%).
The most optimistic scenario would leave PJM with an $18 million reserve at year-end; the most extreme scenario would reduce the reserve to only $3 million. “PJM is not expecting to fall below zero” in reserves, Drauschak said.
PJM is planning for as much as a $26 million reduction in its Schedule 9 revenues because of reduced energy use during the coronavirus pandemic. | PJM
The RTO has cut some operating expenses in response to the lower revenues and unexpected pandemic-related costs, she said. It also executed a short-term $50 million liquidity support agreement with PNC on April 23 and asked FERC to increase its borrowing authority to $200 million. A ruling from the commission is expected by May 26.
The RTO is cutting expenses through a freeze on new hires and reductions in spending on travel and training.
To address cash flow issues, PJM has a $150 million line of credit. It expects its peak borrowing to be between $130 million and $139 million, likely in the third quarter.
Return to ‘Normal’ not Close
Scott Heffentrager, senior director of physical security, briefed members on Pennsylvania’s plan for reopening its economy but said Montgomery County, where the RTO is headquartered, is still seeing too many new COVID-19 cases to contemplate a return to business as usual.
Gov. Tom Wolf has a three-phase reopening plan. All 67 counties are currently in the “red” stage’s stay-at-home rules, with only life-sustaining businesses in operation.
PJM executives and Independent Market Monitor Joe Bowring held a panel discussion on the events of 2019. | PJM
It plans to move to the “yellow” stage for 24 mostly rural counties on May 8. That will ease stay-at-home restrictions, although the state will continue to require telework where feasible.
The final “green” stage, which will lift the safety order and stay-at-home restrictions, will require counties to average less than 50 new positive cases per 100,000 residents over 14 days. That computes to 415 new cases over two weeks in Montgomery County (~30/day).
The county averaged 204 positive cases a day over the last two weeks, Heffentrager said. “So, we’re well behind the criteria to move from red to yellow.”
Herling Retires
After a 30-year career at PJM, Steve Herling will retire on June 30. He began his career in May 1990 as a professional engineer, working his way up to vice president of planning for in 2004 before beginning his transition last year as executive consultant.
Ken Seiler, Herling’s successor as vice president of planning, provided remarks in recognition of Herling’s retirement, joking that he was “someone to look up to” as the tallest person on the PJM campus. Seiler said Herling, who stands 6’8″, was affectionately referred to as the “tower of power” among PJM staff, and thanked him for hiring him in June 2000.
Steve Herling, PJM | PJM
Herling was one of the original architects of the Regional Transmission Expansion Plan in 1998, Seiler said, and was widely regarded as one of the most knowledgeable people on PJM’s staff.
“Steve knows the bulk power system of our region like nobody else,” Seiler said. “And our lawyers love to have him testifying at the regulatory hearings because he literally knows everything there is to know seemingly off the top of his head.”
Herling said it was hard to believe he had been with the company for 30 years. He said he had many wonderful experiences being a part of the RTO.
He said he mostly wanted to thank the planning staff who worked under him, saying he could not have done half of his accomplishments without their dedication.
“It’s easy for us to look good when we have such a strong group of people backing us up,” Herling said. “I’m sure there will be a lot more success stories in PJM’s future.”
New CEO Comments
PJM CEO Manu Asthana said he would never have imagined making his first Annual Meeting address over teleconference.
Asthana, who took over leadership on Jan. 1, said he also would have never envisioned the amount of change in the world during the first four months of his leadership of the RTO. He said the COVID-19 pandemic has created unique challenges for PJM and himself personally to come up to speed in his role.
Asthana said he chose to come to PJM because he wanted to have an impact on an organization that is directly affecting 65 million people each day. He said he had seen the rapid energy transition taking place in the U.S., driven by technologies as well as environmental preferences and policies, and he saw PJM being at the center of that revolution.
“It’s been quite an interesting time to take over as CEO of a complex and important organization like PJM in the middle of this disruption,” Asthana said. “It’s hard to believe it’s only been four months in the role, but it has been a meaningful and impactful and pretty stressful four months.”
Tariff, OA Changes
The committee approved administrative revisions to the Tariff, Operating Agreement and Reliability Assurance Agreement as recommended by the Governing Document Enhancement & Clarification Subcommittee.
California renewable energy prices fell to record lows in 2019, driven by the proliferation and falling costs of wind and solar power, the Public Utilities Commission said Monday in its annual report to the State Legislature.
Renewable portfolio standard contract prices dropped to 2.82 cents/kWh in 2019, compared with 3.81 cents/kWh in 2018, for all RPS-eligible energy, the CPUC said in its 2020 Padilla Report. RPS contract prices dropped an average of 12.7% per year between 2007 and 2019, it said.
The state’s three large investor-owned utilities continued to pay at a far higher rate because of renewable contracts signed last decade before prices fell dramatically. In 2019, the IOUs procured renewable power at an average cost of 10.23 cents/kWh, down from 10.57/kWh in 2018. The IOUs total procurement costs fell from $5.6 billion in 2018 to $5.4 billion in 2019, the report said.
Historical trend of all load-serving entities’ RPS contract costs by technology and year of execution from 2003-2025 (real $) | CPUC
California’s RPS program requires IOUs, electric service providers and community choice aggregators to purchase a third of their retail energy from renewable sources by 2020 and 60% by 2030. The state has a goal of using all carbon-free electricity by 2045 under Senate Bill 100, passed in 2018. (See CPUC Approves Big Boost in Storage, Solar Targets.)
The IOUs and small and multi-jurisdictional utilities (SMJUs) predicted they will meet or exceed their RPS procurement obligations this year, the report said. CCAs, which make up a growing segment of load-serving entities in California, forecast a procurement shortfall but said they were seeking additional resources.
The CCAs increased their procurement of renewables by 55% to 15,500 GWh and executed the majority of new RPS contracts in 2019, the CPUC said. Their total annual RPS procurement spending increased from $555 million in 2018 to $932 million in 2019, it said.
The California Public Utilities Commission issued a proposed decision last week that would speed the interconnection of microgrids to utility distribution systems in anticipation of the state’s upcoming fire season and the public safety power shutoffs (PSPSs) that will likely accompany it.
The proposal, issued April 28, would order utilities to prioritize microgrids and resilience projects that could be put in place by Sept. 1. It is intended to “rapidly develop and deploy projects that could keep electricity on for critical facilities and other customers during power outages,” the CPUC said.
Commissioner Genevieve Shrioma | CPUC
“Wildfire season will begin soon and, if like last year, it will surge this fall, bringing public safety power shutoffs and other outages,” Commissioner Genevieve Shiroma said in a statement. “Microgrids using independent energy supply can provide essential backup and resiliency for communities affected.”
The proposed decision makes recommendations to reduce the time it takes to connect microgrids and distributed energy resources to the grid starting with this fall’s fire season. Among its provisions, the proposal would require the state’s big three investor-owned utilities to standardize application processes for project approvals, expedite utility sign-off on projects, and accelerate interconnection of projects for key locations, customers and facilities.
It would conditionally approve projects by Pacific Gas and Electric to upgrade substations that can be quickly energized with local power sources. It also would allow PG&E to procure temporary, portable generators to use at substations and “key locations of public benefit” for the 2020 wildfire season, which typically starts in summer and worsens in the fall.
Under the proposal, San Diego Gas & Electric would be authorized to move ahead with software and hardware upgrades to “enhance microgrid operations and to augment and interoperate with SDG&E’s existing advanced distribution management system and microgrid projects.”
The rulemaking falls under Senate Bill 1339, passed in 2018, that directed the CPUC to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations” by Dec. 1.
It gained momentum after the decision by PG&E to cut power to hundreds of thousands of customers last fall angered public officials including Gov. Gavin Newsom and CPUC President Marybel Batjer, who called the utility’s actions “unacceptable.”
The proposal is the latest in a series of actions taken by the CPUC to mitigate the effects of PSPSs. In January, the commission approved $830 million in new funding to subsidize self-generation in fire-prone areas, bringing its total funding for self-generation projects to $1.2 billion. (See CPUC Proposes New Power Shutoff Guidelines.)
The CPUC is accepting public comment on the proposal and plans to vote on it June 11.
The economic fallout from the COVID-19 pandemic will weigh most heavily on utilities most dependent on commercial and industrial load, two power industry researchers told the Northeast Energy and Commerce Association (NECA) on Thursday.
About 60 participants tuned into NECA’s “Pandemic, Power Demand and Profits” webinar to learn how the stay-at-home orders and the contraction in U.S. second-quarter GDP are impacting the utility industry.
The U.S. has only 4% of global population but accounts for a third of the world’s COVID-19 cases. The webinar examined where a recession will hit hardest in the U.S. electricity industry — and who could ride through the storm relatively unscathed.
The panel also looked at how the pandemic will affect the level and shape of load in future, and whether commercial load will become lower and flatter than before the shutdown.
Load Composition Determines/ Downturn Fate
Panelists Hugh Wynne and Eric Selmon, both longtime international power project developers, together founded Power Research Group and head up utilities and renewable energy research at investment consultancy SSR.
The pandemic shutdown finds Selmon holed up with his wife and children in Tel Aviv, Israel, while Wynne is doing the same on the coast of Maine.
Estimated change in utilities’ Q2 2020 retail electricity revenue at various rates of quarterly GDP growth | EIA, SSR
Wynne said the pair’s research indicates the recession will impact power sales most severely in those regions — and among those utilities — with the highest share of C&I load.
“Over the last couple of decades, changes in GDP can explain about 40% of the annual variation in commercial and industrial electricity revenues,” Wynne said. “In the residential sector, there is not a very strong correlation between GDP and revenues from residential demand, and that has important consequences.
“Conversely, regions that have high levels of residential demand will be cushioned from that impact. And importantly, because this recession was triggered by and coincides with the state lockdowns, a second development will alleviate the financial burden on these utilities, and that is the increase in residential demand during the lockdowns,” he said.
Residential demand is up about 10 to 15% nationally over the past month, which will have a material mitigating effect on the downturn in C&I revenues from the utilities’ perspective — it won’t offset it completely, but it will reduce the reduction in revenues, Wynne said.
At the retail level, rates for electricity vary dramatically by customer segment.
Impact of lower C&I revenue, and 10% higher residential sales, on utilities’ Q2 gross margins at various rates of quarterly GDP growth | EIA, SSR
“Residential rates are by far the highest, commercial rates perhaps two-thirds on average nationally, in terms of the residential rate, and industrial revenues per megawatt-hour are perhaps a half of the residential rate,” Wynne said.
As a consequence, the downturn in C&I demand will have a less-than-proportional impact on utility revenues while the increase in residential demand as the lockdowns persist will have a greater-than-proportional impact, he said.
New York vs. New England
In terms of individual utilities and regions, Selmon and Wynne concentrated on the Northeast and found some utilities better positioned because of their high levels of residential demand.
National Grid and Emera, for example, have very high levels of residential demand in their electricity sales profiles at 70% and 52%, respectively. The pair categorized Avangrid and Eversource Energy as moderately well situated to absorb the impacts from the downturn, at 45% and 40%, respectively, and others such as Consolidated Edison, at 32% residential demand, not well positioned.
“In Con Ed’s case, almost two-thirds of demand comes from the commercial segment, and that renders them particularly vulnerable to the economic contraction,” Wynne said.
Selmon noted that “the country experienced a fairly mild winter, but particularly in the Northeast and parts of the Midwest, it was significantly colder than average in March and April, so when you weather-adjust, you would see a greater impact: a greater decline in peak loads from before the lockdown.”
In contrast to New York City and its concentration of commercial demand, New England as a whole is much more heavily weighted to residential demand, Selmon said.
“New England is different from other parts of the country in being more gas generation, so here there’s less of a stack to shift around,” Selmon said. “When demand declines you will see more of an impact on heat rates. In other parts of the country the heat rates have held up fairly well … in Texas demand is actually up.” The Midwest was already seeing a decline in industrial demand before the lockdown because an industrial recession appeared to be starting, but now the region is seeing declines in commercial load as well, he said.
Gross Margins and the Long View
Industrial demand is about a quarter of total demand nationally, yet the contribution of the industrial segment to utility gross margins nationally is only about an eighth of the total.
On the other hand, residential demand is about a third of total demand nationally, but the contribution of those residential customers to utilities’ gross margins is slightly over half.
“What we’ve done here is to translate our estimate of the decline in C&I revenue, and our estimate of the increase in residential revenue, to show their impact on the total gross margin of utilities in the second quarter,” Wynne said.
In Wynne and Selmon’s central case of a 30% decline in second-quarter GDP, the decrease in industrial revenues will probably erode the total gross margin of the utilities by about 2%. Combining the industrial profile with a 3.3% decline in commercial revenues and an offsetting 4.3% increase in residential revenues would result in a 1% decline in utility gross margins during such a quarter.
Estimated change in utilities’ Q2 2020 C&I electricity revenue at various rates of quarterly GDP growth | EIA, SSR
Over the second half of the year, “we’re concerned that the experience of Asia may portend a recurrence of COVID-19 in the future,” Wynne said. “In Asia there’s a group of island nations — Singapore, Hong Kong and Taiwan — that noted considerable initial success in combatting the spread of COVID. But in each of those countries, there have been renewed outbreaks of the disease and authorities have been forced to reintroduce social distancing measures, and in some cases, particularly Singapore, those new measures are stricter than the ones initially imposed.
“With such a recurrence likely in the U.S., particularly in the fall flu season, we foresee a re-imposition of social distancing by state health authorities, and possibly, in extreme cases, a re-imposition of lockdown.”
Such an eventuality would mean that the typical V-shaped economic recovery chart would instead be a sawtooth pattern resulting from a slower return to normal with alternating quarters of expanding and contracting GDP, he said.
As a result, wholesale electricity markets may see persistent reduced power demand and prices, and regulators will look less favorably on revenue increases and rate base growth, Wynne said. In turn, lower and flatter load profiles may limit opportunities for investment in generation and transmission.
SPP’s Board of Directors last week approved the first two revision requests stemming from the Holistic Integrated Tariff Team’s (HITT) 15-month effort to help the grid operator adapt to the evolving grid and electricity markets.
Gathering virtually for its first meeting since the COVID-19 outbreak began, the board on April 28 signed off on both measures. The changes were previously advanced by the Markets and Operations Policy Committee, Strategic Planning Committee and Regional State Committee.
SPP Chair Larry Altenbaumer opens the virtual April board meeting from his home office.
RR 391, which establishes uniform local planning criteria within each transmission pricing zone under the Tariff’s Schedule 9, received pushback, in line with the frequent tension between transmission owners and customers in SPP’s 19 zones.
As written, RR 391 places the responsibility on the zone’s host TO to facilitate a “consensus-driven” criteria for reliability upgrades, rather than have individual TOs submit their local planning criteria to SPP, to ensure all customers in the zone pay equally for the same types of transmission upgrades. Schedule 9 calculates network service request charges as a ratio share of the monthly annual transmission revenue requirement.
For many transmission customers, the issue was the loss of the words “collaboration” and “consensus” in the RR’s final language.
Golden Spread Electric Cooperative’s Mike Wise said the RR failed to convey the HITT report’s intent.
“The language did fall short,” said Wise, a HITT member. “We spent a huge amount of time discussing how the host utilities in a zone should develop a collaborative process. Certainly, the language should have been a consensus-driven process within each zone. Neither of those words showed up anywhere, and I think we fell short because of that.”
“As a [transmission and distribution user], a small transmission customer being invited to a meeting is one thing. Having your opinion heard or taken into consideration is two completely different things,” Oklahoma Municipal Power Authority General Manager David Osburn said. “I’d like to see a little more teeth, to see the [TDUs] and customers have more meaningful input in the process.”
“The Tariff language … simply requires the big utility in the zone, or the [facilitating TO] to call a single meeting and, based on that, file or not file zonal planning criteria that the FTO determines to be in their best interest,” said consultant Jack Madden, who represents several Texas cooperatives. “We believe this is a far cry from what was hammered out during the HITT discussions.”
Antoine Lucas, SPP’s vice president of engineering, tried to clarify matters by pointing out that it’s up to the entities within the zone to reach agreement.
SPP’s transmission pricing zones | SPP
“Nothing in this language prohibits TOs in the zone from working together to define what consensus means to them and how they want to organize themselves,” he said. “We want to ensure everyone in the zone will have comparable criteria.”
Osburn and three others on the Members Committee voted against RR 391. Wise abstained.
The second Tariff change, RR 401, faced a smoother path to approval, with only one abstention. The measure replaces credits under Tariff Attachment Z2 for certain network upgrades with incremental long-term congestion rights (ILTCRs). It replaces a previous attempt to change the Tariff, which was rejected in January by FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)
Dan Simon, outside counsel for EDF Renewables, spoke out against the measure as he has during previous stakeholder groups, saying SPP’s current ILTCR rules are “inadequate.”
“I think most people would agree. No one has selected the ILTCR option,” he said, calling for SPP to improve the ILTCRs “so they’re more in line with other RTOs.”
SPP staff wasted no time in filing the change at FERC, doing so the day after the board meeting and asking for an effective date of July 1.
The HITT concluded its work last year, handing off its 21 recommendations to various stakeholder groups. The recommendations encompassed four categories: reliability, marketplace, transmission planning and cost allocation.
Directors Suspend Competitive Upgrade
The board sided with recommendations from SPP and the Oversight Committee to suspend a previously approved competitive interregional upgrade, pending negotiations with the seams partner and FERC approval.
The 345-kV Wolf Creek-Blackberry project in Kansas and Missouri was approved by the board last year and included in the 2020 SPP Transmission Expansion Plan, which the board passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the Associated Electric Cooperative Inc. (AECI) transmission system and constructed by AECI.
Because AECI is not a TO under SPP’s Tariff, staff must reach an agreement with it to outline the project’s scope and define cost allocation for its work. The entities have agreed to a joint study schedule to conclude in May, after which they would finalize an agreement that must be approved by FERC before SPP can allocate funds to AECI for the latter’s portion. (See “SPP, AECI Agree to Joint Study,” SPP Seams Steering Committee: April 2, 2020.)
The OC said were SPP to commence its competitive process and issue a request for proposals without reaching an agreement with AECI, “there is significant risk that millions of dollars would be spent on a [competitive selection process] that results in nothing.”
SPP COO Lanny Nickell said were the project not suspended, staff would have to meet a Tariff deadline and begin the RFP process by July without a negotiated agreement and FERC approval in hand.
“There are risks associated with not suspending the project and beginning the RFP process,” Nickell said. “It could impose costs on members if AECI does not ultimately agree to what they have to do on their end.”
For the time being, AECI is projected to spend up to $2 million on a substation. “But if other upgrades are needed to accommodate this request, that opens up a whole series of discussions with AECI and our members, because that would create additional costs,” Nickell said.
Wise said he thought the OC made the correct decision.
“This falls in line with what I’ve been advocating, which is achieving a higher degree of quality in transmission buildouts,” he said. “These are 40-year assets that have to be paid by all consumers in the footprint. We need to ensure AECI pays its fair share.”
“The idea to initiate a process where the clock would be running, and those members wanting to participate would have to start spending time and money to develop a bid, doesn’t seem prudent,” said Brett Leopold, with independent transmission utility ITC Great Plains.
“This project can still be suspended or canceled at a later date if it’s not deemed to be right,” Evergy’s Kevin Noblet said. “Sending an RFP out on the street when the only thing at risk is a few hundred thousand dollars, if that, seems like a risk worth taking.”
Evergy was one of four member companies to oppose the recommendation. Two other members abstained.
COVID-19 Alters Sugg’s Transition Plan
Delivering her inaugural CEO report to the board and committee, Barbara Sugg had to admit her transition into the position held for 16 years by the retired Nick Brown was “not exactly turning out like I had expected.”
Sugg, who was selected to replace Brown in January, had intended to spend much of her first 90 days in the role traveling across the footprint and visiting with SPP’s many stakeholders. (See Sugg Prepares to Take ‘Dream Job’ at SPP.)
Those plans were waylaid by the COVID-19 pandemic after she had met with a dozen different companies.
“The roadshow stopped just as soon as it started. I’m really disappointed I had to cancel many of those meetings,” she said. “COVID-19 may have sidelined me right now, but I look forward to getting back on the road.”
Sugg has continued to conduct virtual meetings and has made individual calls with each of the regulatory commissioners in SPP’s footprint. “It’s good for those commissioners to hear from me so we can start building trust and respect that is mutual.”
Saying it’s “inevitable” that an employee will eventually test positive for COVID-19, Sugg said, “We continue to hope for the best and prepare for the worst.”
There is a silver lining to the pandemic. With the reduction in travel and meeting expenses, SPP has over-recovered about $2.5 million in administrative fee revenues through March. Sugg said that with “lots of meetings planned to be virtual for many months to come,” that number will grow.
However, the pandemic has also resulted in lower demand, “putting pressure on 2020 rates,” she said. SPP has also incurred about $340,000 in net savings by increasing and using the engineering staff, rather than consultants, to manage the interconnection queue.
Sugg said resolving seams issues with SPP’s neighbors remains one of the grid operator’s key goals. “We remain committed to win-win solutions on the seams,” she said.
Lowest Prices Ever for Integrated Marketplace
Keith Collins, executive director of the SPP Market Monitoring Unit, shared with directors and members a draft of the 2019 State of the Market report that found the footprint’s energy prices were the lowest since the Integrated Marketplace went live in 2014.
Day-ahead prices averaged about $22/MWh and real-time prices averaged about $21/MWh, down from $25/MWh in 2018, Collins said. With gas prices below $2/MMBtu, also among the lowest since 2014, natural gas-fired resources frequently set market prices.
Collins also said the region’s frequently constrained areas have all been removed, partly because of transmission additions that have shifted congestion and leveled the footprint’s market prices. He said the MMU believes Central Oklahoma and the Tulsa area could potentially become frequently constrained areas in the future.
SPP’s energy prices are the lowest since the Integrated Marketplace went live in 2014. | SPP Market Monitoring Unit
According to the report, the reliability unit commitment process’ make-whole payments rose 55% to nearly $70 million last year. Collins attributed the increase to more resources being brought on from the RUC processes, including manual commitment for capacity needs.
The MMU also said wind generation continues to catch up with coal. Wind resources accounted for 27% of all generation in 2019, up slightly from 23.5% the year before. Coal generation, meanwhile, fell from 42% in 2018 to 35% last year.
The report outlined recommendations for SPP’s market, including improving price formation during emergency and scarcity conditions, improving outage coordination, increasing flexibility and enhancing the ability to assess a range of transmission planning outcomes.
Collins said the MMU has noticed several concerning trends, including a 70% increase in scarcity intervals, increased negative pricing during the overnight hours, and increased generator outages and emergency conditions.
“Scarcity intervals highlight an increase in the volatility that occurs in the real-time market,” Collins said. “It’s driven by short-term, ramping-related scarcity events that happen on the system. That’s why we’ve been supportive of ramping products.”
The MMU’s market-enhancing recommendations include improving price formation during emergency conditions and scarcity events, incentivizing capacity performance, and updating and improving outage-coordination methodology.
“It’s important to set proper prices during these types of events,” Collins said. “Scarcity events are actually reflecting events that are happening on the system. You want the power flowing in the right direction, particularly when scarcity events occur.”
SPP has already formed the Generator Outage Task Force to improve outage coordination.
Staff Strengthening TCR Credit Practices
Director Graham Edwards, chair of the Finance Committee, said the Credit Practices Working Group (CPWG) has spent the last 18 months trying to strengthen the use of credit in SPP’s transmission congestion rights (TCR) market. The work follows the 2018 GreenHat Energy default in the PJM market, which left members liable for more than $100 million. (See FERC Orders PJM to Unwind GreenHat Settlements.)
The group is recommending increasing the minimum capitalization for participants in the TCR market to either at least $20 million in assets or $10 million in net worth, or by increasing alternative collateral requirements. The CPWG is also recommending a strengthened credit application and minimum collateral on all TCR portfolios.
The Finance Committee has approved the recommendation and sent it through the stakeholder process for Tariff language development.
The board approved the committee’s recommendation that it accept accounting firm BKD’s 2019 audit report and findings. BKD said it did not find any issues or concerns in its review of SPP’s accounting practices.
Digital Release for 2019 Annual Report
The virtual meeting marked another break in tradition for SPP. The RTO’s annual report was posted digitally instead of being placed in each director and member’s chair.
Entitled “Integration,” the report includes former CEO Brown’s final introductory message and focuses on the five major initiatives facing SPP: seams issues, transmission, Western expansion, the HITT recommendations and providing member value.
Consent Agenda Includes Exit Fee Changes
The board’s consent agenda, unanimously endorsed by the committee, included revisions to SPP’s bylaws and membership agreement that define the exit fees for transmission-owning and non-transmission-owning members upon their withdrawal.
FERC in December scuttled SPP’s alternative proposal of a $100,000 exit fee and rejected a rehearing request. It also directed the RTO to make a compliance filing that ensures non-TO members pay a lower fee should they leave (EL19-11). (See FERC Denies Rehearing of SPP Exit Fee Decision.)
Other items on the consent agenda included:
An amendment to the membership agreement that allows Roughrider Electric Cooperative, embedded in the Integrated System as a Basin Electric Power Cooperative member, to join SPP as a TO. Roughrider, a non-transmission-owning member of SPP as of April 30, will transfer functional control of its transmission facilities to the RTO, pending FERC approval. The IS joined SPP in 2015. (See Integrated System to Join SPP Market Oct. 1.)
The nomination of Kansas Electric Power Cooperative CEO Suzanne Lane to the Human Resources Committee.
Revising the Corporate Governance Committee’s scope to use independent executive search firms to replace a director or fill a vacancy on the board.
Baseline resets for five previously approved transmission projects. (See “Members Approve 1 RAS, Retirement of Another,” SPP MOPC Briefs: April 14, 2020.)
The PJM Markets and Reliability Committee deferred a vote on a proposed issue charge to consider rule changes for hybrid resources after members questioned the RTO’s plan to assign it to a new senior task force.
PJM has more than 10,000 MW of co-located generation and energy storage hybrid resources in the interconnection queue. RTO staff intend to focus the effort primarily on solar-battery hybrids, which represent more than 95% of the total, with the remainder wind-battery and gas-battery.
Since introducing the issue charge at the March MRC meeting, PJM added to the education topics the interconnection queue process for hybrids, including how existing material modification rules apply. It also pushed the start date from May 1 to July in response to concerns over the MRC’s workload. (See PJM MRC Moves Forward on Storage, Hybrids.)
PJM’s Scott Baker said staff recommended creating a senior task force because of the varied issues raised by hybrid configurations. “There’s enough cross-functional [issues] here between planning, markets and operations to warrant this being a separate group,” he said.
Under Manual 34, a senior task force reports to a senior standing committee (the MRC or Members Committee) and is created for “consideration of specific issues that have the potential for large dollar or major policy impacts.”
Dayton Power & Light’s John Horstmann said that while he supported the initiative, it should be a task force under one of the standing committees — the Market Implementation Committee, Operating Committee or Planning Committee — rather than a senior task force.
“To the extent it crosses MIC, OC or PC interests, there is no reason the other committees can’t be invited” to the meetings, he said.
PJM’s Dave Anders acknowledged that the RTO has had “a bit of a struggle” with assigning new projects because of conflicts between concept and practice.
“In theory, we could invite others to a task force under the MIC, but in practice that doesn’t always happen,” he said. “The senior task force seems to get more attention and … participation.”
Horstmann said he was “frustrated” because he and others in the Stakeholder Forum “met for quite a few months to develop clearer” rules for such assignments in Manual 34.
“We think we’ve fixed this problem, but it hasn’t been presented to members for endorsement,” he said.
After discussion, MRC Chair Stu Bresler decided to defer action on the issue charge so staff could reconsider the assignment.
Horstmann explained after the meeting that the members created a table for inclusion in Manual 34 listing “the different types of stakeholder groups with a description of their function and use, including the expected length of time that they would meet.”
Emerging Technologies Subcommittee Proposed
Stakeholders also expressed concerns about the reporting structure for a new Emerging Technologies Advisory Subcommittee (ETAS) that PJM proposed to support its Advanced Technology Pilot Program (ATPP). The ATPP provides a testing ground for studying the viability of integrating new technologies that could enhance system reliability, operational and market efficiency, and resilience.
Eric Hsia of PJM reviewed the subcommittee’s charter, which the MRC will vote on May 28. Hsia said PJM was acting on the issue based on stakeholder feedback and the RTO’s recognition that it currently doesn’t have a forum to discuss emerging technologies and pilot programs.
The subcommittee would identify operational, planning and markets-related issues and make recommendations, Hsia said. In addition to hosting technical education sessions on emerging technologies, it would create and review ATPP procedure documentation to incorporate stakeholder feedback into the process and provide additional transparency. PJM would continue to maintain authority over the ATPP, and the subcommittee would not make decisions on selecting specific pilot projects. The group also would identify benefits of new technologies and obstacles to implementing them.
Gary Greiner, director of market policy for Public Service Enterprise Group, said he supports the idea but that the subcommittee should not report to the MRC, as proposed.
“I think most of what you’re going to see would be operations-based. I’m wondering why it wouldn’t be down at the standing committee level,” he said. “I really think there’s value in having those issues pass through that lower-level layer to be fully vetted.”
Hsia said staff did discuss having the ETAS report to a standing committee but decided on the MRC as its parent because of “the nature of pilot programs and the cross-functional nature of the discussions.” Many issues that come before the new group would involve planning as well as operations, he said.
Paul Sotkiewicz of E-Cubed Policy Associates asked if there was a way to combine the solar hybrid resources issue previously discussed with the ETAS as a way to pare down the number of stakeholder groups.
“It’s just becoming unwieldly to follow all of the committees at this point,” Sotkiewicz said.
Bresler, PJM’s senior vice president of market services, said the location of the committee is “one thing we’ll examine prior to bringing this back for a vote.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the ETAS will help stakeholders understand the functionality and benefits of emerging technologies.
Poulos noted that Thursday’s MRC agenda included several emerging technologies, including hybrid storage and HVDC converters.
“I’m glad that PJM is getting ahead of this,” Poulos said.
‘Credit’ Subcommittee Proposed to Change to ‘Risk Management’
PJM gave a first read to a proposal to rename the Credit Subcommittee as the Risk Management Subcommittee and amend its charter to broaden its authority to include market risk.
Under the revised charter, the renamed subcommittee also would be elevated, reporting to the MRC rather than the Market Implementation Committee. Chief Risk Officer Nigeria Poole Bloczynski said the change would acknowledge that the broader consideration of risks “may incorporate aspects outside of the sole purview” of the MIC.
Anders said the restructured group would be a venue for considering risk management as a wholistic topic. He previously said the subcommittee — which hasn’t met since December 2018, as members have focused their efforts on the Financial Risk Mitigation Senior Task Force in the wake of the GreenHat Energy default — was the best venue for considering a planned problem statement over a credit risk issue the RTO identified in February. (See “Scope, Name Change for Credit Subcommittee?” PJM MIC Briefs: March 11, 2020.)
Bloczynski noted the committee’s charter has not been revised since 2010.
“Risk management seems to be an afterthought. No one thinks about it until there’s a problem,” she said. The MRC will be asked to endorse the revised charter at its next meeting.
The revised mission statement says the committee will “discuss and recommend” ways to address market and credit risk issues. It will not “manage, govern or otherwise set policy for PJM.”
Sharon Midgley of Exelon said she thought the charter change should be considered in tandem with how it will potentially impact the scope of the MIC.
“Anything that we’d talk about credit or markets related at this committee, we’re going to want to make sure that the participants in the MIC are aware of it because that impacts them as well,” Midgley said.
Greiner said he views “market risk” as a term that can be defined differently depending on who is being asked. He said he would like to see PJM put a clear definition of the term in the charter.
“If you have a definition for market risk, it’s going to help inform the scope of what we’re doing here,” Greiner said. “I think it’s probably best to embed it in the charter itself so we can get a sense of what’s in and what’s out.”
Sotkiewicz encouraged PJM to include market design risks in the scope of the charter. He said having a core group of PJM staff and possibly stakeholders working together to look at market designs and finding problems that are there before they turn into a major issue that results in a FERC filing or a financial hit to membership would be of great benefit.
“Those risks are always going to be out there, and if we can get ahead of the game, we in the membership would be much better off,” Sotkiewicz said.
Surety Bonds
The MRC heard a first read of a proposal to allow market participants to use surety bonds as collateral.
Bonds can be less expensive than letters of credit but are dependent on the credit and risk profile of the market participant, PJM said.
The MIC endorsed two proposals in October 2018, with 61% supporting use of surety bonds as collateral for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
A second proposal allowing surety bonds as collateral for all market purposes including FTRs won 58% support. It would set a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer. PJM said it supports the first proposal, citing limited experience in the use of surety bonds in FTR markets and the large size of past FTR defaults.
In December 2018, the MRC agreed to defer action on the proposals until completion of the independent consultants’ report on the GreenHat default. It was deferred again in April 2019 pending appointment of a chief risk officer and appointment of a new CFO.
If the Tariff change is approved, PJM said it will require use of bond companies on U.S. Treasury Department’s certified list and a minimum credit rating of A with S&P Global Ratings; A with Fitch Ratings; A2 with Moody’s Investors Service; or A with AM Best. PJM also will require acceptance of one-day payment demand terms.
The MRC will consider endorsement on May 28, with the MC taking it up in June.
Governing Documents Cleanup
In its only voting action aside from approving the minutes for the MRC’s March meeting, the committee approved administrative revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement, as recommended by the Governing Document Enhancement & Clarification Subcommittee.
PJM stakeholders debated for nearly two hours Thursday over transmission owners’ spending on end-of-life (EOL) projects, suggesting there is little chance for compromise on an issue that has been disputed for years within the RTO.
Three EOL proposals were given first reads at Thursday’s Market and Reliability Committee meeting, setting up votes at the next MRC meeting on May 28. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December.
Three Proposals
A proposal by a group of PJM stakeholders, including American Municipal Power and Old Dominion Electric Cooperative, would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would be made a new category of regionally planned projects. It was endorsed by the PJM Industrial Customer Coalition, the Public Power Association of New Jersey, Consumer Advocates of the PJM States (CAPS) and the D.C. Office of the People’s Counsel.
LS Power supports the stakeholder package but would require six years’ notice for lower-voltage facilities and at least eight years’ notice for facilities of 230-kV and above.
PJM also offered a package requiring TOs to identify EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. Like the stakeholder and LS Power plans, PJM’s proposal would require each TO to have a formal program for EOL determinations. The RTO said it would prevent TOs that don’t already have a EOL determination process from using a “run to failure” asset management approach.
Under current rules, said Mark Ringhausen, vice president of engineering for ODEC, some TOs don’t identify EOL projects, choosing instead to replace “pieces and parts.”
“Some have told me that they never make EOL determinations,” Ringhausen said.
Divergence of Plans
But PJM disagreed with the stakeholder proposal on the RTO’s jurisdiction over EOL facilities, saying the Consolidated Transmission Owners Agreement (CTOA) transferred to PJM only the responsibility to prepare an RTEP “for the enhancement and expansion” of the transmission system to meet demands for firm transmission service. Section 5.2 of the CTOA says, “PJM shall not challenge any … sale, disposition, retirement, merger or other action.”
Dave Souder, PJM senior director of system planning, said the proposal honors the TOs’ responsibility over asset management decisions while allowing the RTO to determine when an RTEP project is more cost-effective than a TO’s proposed replacement. “We believe the PJM package takes a reasonable approach,” he said.
Several parties, including AMP and ODEC, insisted the FERC rulings do not preclude their proposal. They said the PJM proposal lacks transparency and would not require TOs to have EOL criteria or to share the list of EOL projects with stakeholders. Souder said PJM hasn’t decided whether the retirement list would be public.
Ed Tatum, AMP’s vice president for transmission, said PJM data from 2019 show $4.8 billion in TO supplemental projects, about 75% of which are for EOL assets that could benefit from longer-range planning. Robert Taylor of Exelon said he disagreed with the $4.8 billion statistic, saying the dollar amount appeared to combine supplemental and baseline projects, inflating the number by as much as $1.5 billion.
Tatum conceded that the retirement of a transmission asset should be determined by the TO that owns it. But he said PJM should take over planning once a retirement decision is made.
“Asset management includes operational maintenance activities, as well as the decision as to when an asset has reached the end of its life,” Tatum said. “But asset management ends at that point, and planning begins. … We need to have the assurance that this is being planned by an independent organization that is not bound by its stockholders to put together a construction project.”
“We’re supposed to be working together and not going straight to legal arguments,” Poulos said. “The stakeholder process does not work if we’re just going to go to FERC with things.”
Alex Stern of Public Service Electric and Gas said TOs worked hard for a compromise problem statement and issue charge when EOL was brought up at Planning Committee meetings last year but that an agreement could not be reached. (See PJM Members Debate Dueling Tx Replacement Plans.)
Stern said he still had hope that a compromise could be reached during the special stakeholder process in the MRC over the last five months. But he said the packages that emerged are an attempt “to leverage the stakeholder process” to force PJM to make a filing at FERC that individual stakeholders should be making themselves.
“If stakeholders want to challenge the FERC-approved paradigm governing the authority of TOs to make determinations regarding the end of the useful life of their asset … there’s absolutely nothing stopping them from doing so,” Stern said.
John Horstmann of Dayton Power & Light agreed, calling the EOL stakeholder meetings a “scorched-earth process” to force PJM into a Federal Power Act Section 205 filing. Horstmann said the issue should have been brought to FERC as a Section 206 filing rather than going through the stakeholder process.
Stakeholders filing under Section 206 must first prove the RTO’s existing rules are unjust and unreasonable to win FERC approval of changes. A PJM filing under Section 205 would not need to make that showing, needing only to convince the commission that its new rules are just and reasonable.
The Members Committee has Section 205 filing authority over the Operating Agreement (OA); the PJM Board of Managers has Section 205 authority over the Reliability Assurance Agreement and the Open Access Transmission Tariff (excluding provisions under the exclusive control of the TOs).
The stakeholder and LS Power proposals would require changes to the OA.
PJM said its proposal would only require manual changes. LS Power’s Sharon Segner disagreed, saying FERC Order 1000 requires such planning process rules be included in the OA. She also said the PJM proposal fails to eliminate “redundancy between the supplemental and regional planning process” that would require an OA fix.
Stern said the focus on EOL by some of the stakeholders seems to be less on planning criteria and appropriate decision-making to ensure local and regional grid reliability, and more on the dollar amount being invested. He said transmission decisions are supposed to be made on ensuring the reliability of the grid and not the cost.
“PJM certainly has a role to play in planning, but it is not to decide how a transmission owner goes about addressing the impact of the end of useful life of an asset,” Stern said.
Tatum said he agreed with Stern’s assertion that planning shouldn’t be based solely on costs. But he said he would have more confidence that projects were being done in the most cost-effective way if PJM was conducting the planning.
Tatum said the TOs “unfairly discount” the importance of the PJM stakeholder process and the rights of the rest of the stakeholders. He said that since the inception of PJM as an RTO, the TOs demanded many of the provisions in the OA so they could have control over the new entity that was being developed.
“It’s not just [TOs that are] concerned about reliability and keeping the lights on,” Tatum said. “We all have a vested interest in that. But we see a majority of planning being driven outside of [the RTEP] process. Independent planning is essential in order to have successful markets, and we’re moving away from that.”
Susan Bruce, representing the PJM ICC, said industrial customers have seen their transmission bills increase “exponentially” over the past two years, largely because of EOL costs. Aligning the EOL asset management process with RTEP would ensure the transmission investments being made are cost effective and well planned, she said.
“Industrial customers want to see a reliable and robust grid, but they also want to make sure that their investment in transmission is optimized,” Bruce said.
Costs
Citing PJM statistics, Horstmann said that only 30% of the RTO’s transmission system is less than 40 years old, causing a glut of assets nearing their EOL that must be replaced. He said a high price tag is inevitable no matter who oversees the planning.
“You’re looking at a lot of money over the next period of years to basically maintain what we have, let alone improvements,” Horstmann said. “To me, that’s the elephant in the room here. This [dispute] just sort of dances around the edge of that problem.”
Tom Hyzinski of GT Power Group asked how much would be saved by identifying EOL projects six years in advance and making it subject to competitive bidding.
PJM’s Jim Gluck said the MRC will schedule one more special session (May 11 or May 15) to discuss the packages and seek opportunities for consensus before the three proposals are brought to sector-weighted votes May 28. The package with the most stakeholder support and meeting the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support will become the main motion for a vote of the MC.
PJM could support the loss of up to 40% of installed generation capacity on a summer day and up to 60% on a spring day in a worst-case scenario situation in which units were knocked offline from a COVID-19 outbreak among plant workers, the RTO said last week.
Ray Lee, senior engineer in generation, and Jason Sexauer, senior engineer for outage analysis technologies, presented the generator availability analysis to stakeholders during PJM’s weekly coronavirus call Friday.
Lee said the analysis was intended to determine the maximum generation loss PJM could handle without curtailing power to the hardest hit areas. The analysis began by considering the impact of an outbreak at one plant spreading and disabling a generating company’s entire fleet, he said.
Sexauer said the 40% and 60% outage levels in the scenario are about twice as many outages as typically occur during summer and spring. “These scenarios are worst case, far and above what we normally screen for from an operational perspective,” Lee said.
An overlay map of generators located within the PJM footprint compared with cases of outbreaks of COVID-19 | PJM
PJM has not seen any generator outages from the pandemic thus far, they said.
Analysts used overlay maps to compare the highest levels of COVID-19 infection within the PJM footprint with generator locations, Lee said, focusing specifically on New Jersey, the Interstate 95 corridor from New Jersey to D.C., and Chicago and its suburbs.
Lee said coal-fired and combined cycle plants were judged most likely to be impacted by an outbreak because they require higher numbers of on-site personnel to operate.
The final step in the planning process was to define the appropriate time frames for outbreaks at the sites, Lee said.
Because of uncertainty over how long the pandemic will last, PJM decided to perform the studies for the spring and summer peak loads. The findings “could then be used to potentially consider proactive actions, such as limiting future outages if we’re seeing a trend towards these worst-case scenarios,” he said.
Sexauer said four steps were used in the process for calculating the outages, including: selecting the hypothetical generation units that would go offline; building an “all-in case” for May 4 and July 7 using normal load on those dates; creating an “all-out case” where all scheduled transmission and hypothetical generation outages from COVID-19 were applied; and running a DC/AC contingency analysis on the hypothetical cases to look for thermal overloads and “non-converged contingencies,” in which no solution is found.
He said that while running the analysis, PJM found that thermal issues with the grid were more prevalent in the spring and voltage collapse issues were more prevalent in the summer. About 5,200 cases were analyzed, requiring two days of computer runs.
