Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
G. The committee will be asked to endorse a minor correction to Manual 18: PJM Capacity Market regarding an effective date for notifying pseudo-tied resource owners of their assigned locational deliverability area prior to each delivery year. The revision was endorsed as a “quick fix” at last month’s Market Implementation Committee meeting following a discussion in which some members objected to the process and suggested further talks on lingering pseudo-tie issues. (See “Manual 18 Update,” PJM MIC Briefs: Oct. 7, 2020.)
B. Stakeholders will be asked to endorse the installed reserve margin (IRM) and forecast pool requirement (FPR) values included in the 2020 Reserve Requirement Study results. PJM is recommending an IRM of 14.4%, down from 14.8% in 2019. The FPR is essentially the same as 2019, at 1.0865 (8.65%) instead of 1.086 from the previous year. The study determines the IRM and FPR for 2021/22 through 2023/24 and establishes the initial values for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties. (See “IRM Study Results Endorsed,” PJM MRC/MC Briefs: Oct. 29, 2020.)
Pacific Gas and Electric on Thursday acknowledged it needs to get better at notifying local authorities and customers before shutting off power to prevent wildfires, but the utility said it performed far better this fall than it did last year.
In its report to the California Public Utilities Commission on the public safety power shutoffs (PSPS) of Oct. 25-28, the largest this year, PG&E said it had generally met its goals of notifying emergency officials and residents about potential blackouts in the days ahead of an event, but it still sees “opportunities for improvement”
That was unlike the PSPS events last October, when PG&E blacked out more than 2 million residents, many without warning. The utility’s websites crashed under heavy traffic, requiring state agencies to intervene. Its phone lines were also overloaded, and its shutoff maps often were inconsistent or incorrect, then-CEO Bill Johnson said. (See PG&E Restores Power amid Backlash.)
In a meeting Nov. 5, Lee Palmer, director of the CPUC’s Safety and Enforcement Division, said the state’s three big investor-owned utilities, including PG&E, had generally provided PSPS notifications at the “right cadence” in late October, alerting local authorities 48 to 72 hours before an event and telling customers they could lose power 24 to 48 hours beforehand.
| PG&E
In some cases, PG&E failed to notify customers of imminent blackouts because its “process broke down,” Palmer said. Southern California Edison and San Diego Gas & Electric had to make emergency adjustments to their shutoffs because of shifting Santa Ana winds and did not alert some residents before cutting power, he said.
In its report, PG&E said it had made significant strides since last year but acknowledged shortcomings, including that its “delivery of in-event information to [local emergency authorities and customers] needs to improve.”
“Although the situation has improved relative to 2019, there are still some timing inconsistencies between information posted in our online portal, information posted on our customer website and that provided by PG&E liaisons and representatives,” the utility said. “PG&E is working for ways to improve and expedite our information processes and flows to better serve our local partners and first responders.”
CPUC President Marybel Batjer | California State Assembly
CPUC President Marybel Batjer, a vocal critic of PG&E after the 2019 shutoffs, acknowledged that the IOUs had “greatly improved, particularly the PG&E service area, over last year.” She said, however, that the commission was still waiting to hear from county officials and community representatives about their experiences in the blackouts.
In the late-October PSPS events, PG&E shut down power to 345,000 account customers, or about 1 million residents, across 35 counties. SCE blacked out 19,000 customers, and SDG&E shut off power to about 2,900 customers.
“The scale of these PSPS events makes it clear to all of us that the threat of wildfires and impact of PSPS events are not limited to a specific county or city,” Palmer said. “This is a statewide and regional concern.”
Batteries not Provided
CPUC commissioners focused in their Nov. 5 meeting on another problem: the lack of backup batteries provided by IOUs to at-risk residents.
PG&E had promised to deliver 8,000 backup batteries to customers who rely on medical devices in 2020 but had only provided 2,500 units, Palmer said. The utility has said it will deliver 1,500 more batteries by the end of the year, he said.
Rather than address the shortfall in its report, PG&E said it had worked “to provide a cumulative total of approximately 2,525 portable batteries to qualifying customers who need power during a PSPS event” along with food boxes, hotel stays and wellness checks to seniors and others in need.
SCE told the CPUC it would enroll 2,500 residents in its battery-backup program in 2020 but so far has provided only 200 batteries, Palmer said.
Logistical holdups and manufacturing delays caused by the COVID-19 pandemic are partly to blame, he said.
Batjer said she had repeatedly asked the utilities for updates on battery distributions during briefings this year, but the IOUs had only recently provided numbers. The figures fell short of what the commission had hoped for, commissioners said.
“None of them, frankly, lived up to the pledge they made to us in August and then updated by written memo in September,” Batjer said. “It’s something we must indeed continue to work on, so the medically baseline and critically in-need customers have backup batteries that they need during these unfortunately called PSPS.”
ERCOT has learned to live with a wind trough during the early afternoon hours, when coastal breezes drop and West Texas turbines aren’t spinning.
The same phenomenon is taking place with solar energy as it becomes a more reliable resource for the grid.
Dan Woodfin, ERCOT’s senior director of system operations, said last week that the summer sun sets about 7:30 or 8 p.m. in the west, where most of Texas’ wind farms are. The loss of solar production took place shortly after thermal generation shut down after helping meet peak demand, resulting in tighter operating conditions and lower operating reserves.
“There’s kind of an interaction there that hasn’t typically been there,” Woodfin said during a Gulf Coast Power Association webinar Wednesday. “It didn’t cause us a problem, but it did cause us to be a little tighter on some of those days during the early afternoon. As solar continues to grow on the system, it’s something we’re going to have to watch over.”
Additional solar capacity has led to the resource’s increased variability. | ERCOT
ERCOT had about 2.1 GW of additional installed solar capacity at the start of last summer than it did in 2019. Solar farms generally provided between 2.2 and 3.7 GW of energy from 2 to 3 p.m. this summer after producing a fairly steady 1.5 GW during the same period last summer.
“There was a little more variability around the solar output this year,” Woodfin said. “That’s just a matter of having more installed capacity.”
To address the solar trough, staff proposed a system change request (SCR811) that the Board of Directors approved in October. The SCR adds the short-term solar forecast to the resource-limit calculator’s formula for calculating the generation-to-be-dispatched value.
“Every five minutes it will start to look at the drop-off in solar and dispatch the rest of the generation,” Woodfin said.
Dan Woodfin, ERCOT | GCPA
He said the change is designed to avoid adding more system requirements to cover the balancing during each five-minute interval as solar production drops off.
“It will also provide an incentive for [thermal] generation to incrementally stay online as solar drops off by having the prices reflect that,” Woodfin said.
ERCOT began the year with about 2.3 GW of installed solar capacity but expects to end the year with about 5.2 GW. The grid operator expects to install as much as 10 GW of solar capacity by the end of 2022, with more planned for the future. The interconnection queue contains a staggering 81.3 GW of solar projects under some form of study.
The rush to transition to clean energy resources, ambitious offshore wind targets and increasing goals for net-zero emissions are combining to spur cooperation among the New England states, officials said last week during the New England-Canada Business Council’s 28th Annual Executive Energy Conference.
Connecticut DEEP Commissioner Katie Dykes | NECBC
“Our six different states, with all their diversity, are coming together and speaking with a common voice,” Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes said Thursday.
“We desperately need to pursue a more unified market design to ensure that the renewables we’re contracting for are counted and credited appropriately in the capacity market, and that we also can align future procurements with transmission planning,” Dykes said. “We’re at a really positive moment here with our six states and in partnership with the ISO.”
ISO-NE CEO Gordon van Welie, who appeared on the preceding panel, said the RTO has long had the same concerns as the states and that its strategic plan “aligns quite well with the recent statements from the governors of New England.” (See “ISO-NE Shares ‘Vision for the Future,’” NEPOOL Participants Committee Briefs: Nov. 5, 2020.)
Offshore Transmission
Kevin Conroy, Foley Hoag | NECBC
Foley Hoag partner Kevin Conroy asked whether transmission to support offshore wind generation is a regional asset or one that belongs to the generator.
“At the scale that we see offshore wind developing, a generator lead line that is developed as part of one individual project will have some limitations in creating a real optimized transmission system,” Massachusetts Department of Energy Resources (DOER) Commissioner Patrick Woodcock said. “I don’t think we have arrived at the point where the limitations on the transmission system are going to impede [OSW] development, but we will arrive at that point very quickly.” It is important to make sure that the new industry “does not hit a wall, and I am concerned that transmission could bring paralysis to offshore wind development.”
Massachusetts DOER Commissioner Patrick Woodcock | NECBC
The idea of a planned and shared OSW grid is earning support both locally and nationally. At a conference in September, New Jersey Board of Public Utilities President Joseph Fiordaliso said the board was committing to a shared network approach after procuring 3,500 MW of offshore wind, lower than half the state’s goal of 7,500 MW by 2035.
More recently, the National Association of Regulatory Utility Commissioners at its annual meeting Wednesday adopted a resolution urging FERC to consider “that a well planned OSW grid may result in enhanced transmission efficiency and reliability … [and] may reduce the impacts of OSW development on the marine environment and fishery.”
Simon d’Entremont, Nova Scotia | NECBC
Dykes agreed with Woodcock and said that the commitment to decarbonization by most New England governors provides a strong foundation for discussions on regional cost allocations for a shared OSW transmission system.
“The states need to be in the lead and in control of those cost allocation discussions,” Dykes said. “I think that’s one of the big tragedies of [FERC] Order 1000 is that it took away some of the state control.”
“We’re very excited about offshore wind,” said Dan Burgess, director of the Maine Governor’s Energy Office. “We’re slated to have the first floating offshore wind project in the country with our University of Maine-developed Aqua Ventus floating technology, with one turbine in the Gulf of Maine.”
Dan Burgess, Maine | NECBC
Simon d’Entremont, Nova Scotia’s deputy minister of energy and mines, touted the province’s work on tidal energy in the Bay of Fundy. In a rare Canadian reference to hockey, he said, “We’re not looking to go where the puck is; we’re going where the puck is headed.” He welcomed the new U.S. administration as “an opportunity for us to partner on initiatives where we have common supply chains and technologies we want to invest in. … If you are advancing a green economy, we’re doing likewise.”
‘Weird’ Gas Situation
Because the role of natural gas in power production will decline as more renewables come online, some believe that it is irresponsible to think about continuing to use the fuel or invest in anything to do with it.
“As we see declining volumes, particularly on the gas system related to power generation because it’s being displaced by other fuels, we create this very weird and challenging situation where there probably, almost certainly, needs to be more investment in gas infrastructure,” Robb said.
The pipelines and compressor stations may not be needed for the full 50 or 100 years over which such assets might normally be depreciated, he said.
Cheryl LaFleur, ISO-NE | NECBC
“However, it may be really important over the next 15 or 20 years, so there is a real pricing issue around how to recover the cost of those assets,” Robb said. “The New England electrical system is especially vulnerable during the clean energy transition because of not having invested enough in natural gas infrastructure.”
Former FERC Chair Cheryl LaFleur, now serving on ISO-NE’s Board of Directors, said the region will transition to clean energy by “concentrating on the facts” and relying on solid analysis of greenhouse gas emissions outcomes under various scenarios.
Wayne O’Connor, ENMAX | NECBC
“In New England, we’re used to seeing natural gas as baseload, because it displaced a lot of the coal and oil baseload, and it did so very well,” LaFleur said. “But in the future … given the decarbonization goals, I don’t see fossil fuels as a baseload; I see them as a balancing fuel in conjunction with a very heavy portfolio of variable, renewable generation.”
ENMAX CEO Wayne O’Connor said the clean energy transition needs “massive” amounts of capital.
Dan Dolan, NEPGA | NECBC
“If modernizing time-of-use is our approach, we’re in big, big trouble,” O’Connor said. He said he disagreed with a New York Times op-ed on the future of natural gas that decried a “poverty of imagination” in the energy industry. “I think quite the opposite: that our industry has a great deal of imagination; that we’re looking for solutions for a better future.”
Dan Dolan, president of the New England Power Generators Association, said he thought of natural gas’s role “less about a fuel or a specific technology, and more about what are the types of services and attributes we need. The reason that we’re focusing on natural gas is that today it provides that dispatchable energy more cost-effectively than a lot of the alternatives, and as long as it continues to serve that role, while hopefully having the constraint within from an emissions standpoint, then we will continue to rely on it.”
Energy Security
Asked about his main takeaway from the California power troubles this past summer, van Welie said it was an energy-security problem. There was enough nameplate capacity around the system, but there were unusual demand patterns and insufficient supply, he said.
Clockwise from top left: Nova Scotia Deputy Energy and Mines Minister Simon d’Entremont; Kevin Conroy, Foley Hoag; Dan Burgess, Maine; Massachusetts DOER Commissioner Patrick Woodcock; NECBC President Jon Sorenson; and Connecticut DEEP Commissioner Katie Dykes. | NECBC
“It’s all around the assumptions one is making about what resources are going to show up and when, and I think it’s indicative of the kind of volatility we should expect on a system that’s going to be dominated by renewable resources,” van Welie said. “The real question is how much insurance do you want to pay for in the region to cover those types of situations.”
On FERC’s rejection of the RTO’s Energy Security Improvements (ESI) proposal, van Welie said, “We hit ‘pause’ until we can consult with the new commissioners and staff. … Our basic thought is that the concepts behind ESI are still fundamentally sound.” (See FERC Rejects ESI Proposal from ISO-NE.)
PJM’s Independent Market Monitor urged the RTO not to rush into making changes to its capacity market before the recently approved design is given a chance to succeed.
The IMM made the plea in its latest quarterly report, issued Thursday, which noted that PJM energy prices were the lowest in the first nine months of this year compared to any year since the creation of the RTO’s markets in 1999.
According to Monitoring Analytics’ third-quarter State of the Market Report for PJM, the load-weighted average real-time LMP was 23.1% lower in the first nine months of 2020 than the same period last year, coming in at $21.22/MWh versus $27.60/MWh. Of the $6.38/MWh decrease, 57.7% was a result of lower fuel costs, while mild winter weather and the COVID-19 pandemic caused a significant drop in demand.
Components of the PJM day-ahead, annual, load-weighted, average LMP. In the first nine months of 2020, 25.3% of LMP resulted from coal costs, while 17.9% were from gas costs. | Monitoring Analytics
The Monitor used these data to extol competitive electricity markets, noting that “changes in input prices and changes in the balance of supply and demand are reflected immediately in energy prices.”
“The value of markets is under attack, from those who assert that energy prices are too low and from those who assert that markets are incompatible with decarbonization of the power sector,” the Monitor said. “Organized, competitive wholesale power markets are the best way to facilitate the least-cost path to decarbonization. Markets provide incentives for innovation and efficiency. Renewables can compete. Innovation will occur in renewable technologies in unpredictable and beneficial ways.”
The Monitor said fears by over the impacts of the expanded minimum offer price rule (MOPR) have led stakeholders to discuss overhauling the PJM capacity market and states to consider opting out of the market using a fixed resource requirement. It acknowledged there are “clear issues” with the market’s design, including an overstated offer cap, the shape of the demand curve and the application of penalties for nonperformance.
The average real-time and day-ahead supply curves in the summers of 2019 and 2020 | Monitoring Analytics
But the Monitor also said there is no evidence that the new MOPR will make the market less competitive or that nuclear and renewable resources won’t clear it. The IMM noted that PJM has not run its annual Base Residual Auction since 2018 and that capacity prices have not been set for beyond June 1, 2021. “PJM should not rush to overhaul its capacity market again.”
New Recommendations
The Monitor included 10 new recommendations for changes and enhancements to existing market rules and implementation of new rules.
It made seven new recommendations in the Energy Market section of the report, including that:
the temporary cost method and penalty exemption provision be removed;
all units that submit non-zero cost-based offers be required to have an approved fuel-cost policy;
market participants be required to document the amount and cost of consumables used when operating to verify that the total operating cost is consistent with the total quantity used and the unit characteristics;
market participants be permitted to include only variable maintenance costs, linked to verifiable operational events and that can be supported by clear and unambiguous documentation of the operational data, including run hours and megawatt-hours, that support the maintenance cycle of the equipment being serviced or replaced;
offer capping be applied to units that fail the three-pivotal-supplier (TPS) test in the real-time market that were not offer capped at the time of commitment in the day-ahead market or at a prior time in the real-time market to ensure effective market power mitigation when the TPS test is failed;
eliminating up-to-congestion (UTC) bidding at pricing nodes that aggregate only small sections of transmission zones with few physical assets; and
eliminating increment offers, decrement bids and UTC bidding at pricing nodes that allow market participants to profit from modeling issues.
In the Energy Uplift section of the report, the Monitor recommended that PJM designate units whose offers are flagged for fixed generation in Markets Gateway as not eligible for uplift. It said units that are flagged for fixed generation are not dispatchable, and following dispatch is an eligibility requirement for uplift compensation.
The Generation and Transmission Planning section of the report included a recommendation that storage resources not be included as transmission assets for any reason. Monitor Joe Bowring brought the issue up in the Planning Committee on Nov. 4. (See PJM Moves Closer to Endorsing SATA.)
Commenters generally back FERC’s proposal to approve new standards for electric transmission but urged the commission to reject two replacement rules that they said could lead to less efficient use of the grid.
In July, FERC issued a Notice of Proposed Rulemaking to approve Version 003.3 of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities (RM05-5-29, et al.). (See FERC Backs Latest NAESB Rules.)
NAESB is an industry forum that develops standards for the wholesale and retail natural gas and electricity industries. | NASEB
Comments filed earlier this month by the Edison Electric Institute, the Bonneville Power Authority, the ISO/RTO Council (IRC) and Open Access Technology International (OATI) all generally supported the standards adopted by NAESB’s Wholesale Electric Quadrant (WEQ). Version 003.3 includes revisions responding to recommendations by Sandia National Laboratories to strengthen cybersecurity protections; change rules on redispatch services and transmission curtailments; and replace 56 requirements in NERC’s Modeling, Data and Analysis (MOD A) reliability standards addressing the calculation of available transfer capability (ATC). NERC asked that the rules be removed from its standards because they deal primarily with commercial terms rather than reliability.
But none of the commenters agreed with FERC’s suggestion that it might revise its own regulations on ATC. And both BPA and the IRC asked the commission to reject standards WEQ-023-1.4 and WEQ-023-1.4.1, which they said would prevent transmission providers from maximizing the utilization of their systems.
Scheduling Limits
Requirement 1.4 would prohibit transmission providers from granting firm transmission service exceeding the sum of facility ratings for an ATC path; 1.4.1 would limit net interchange schedules to this same amount.
The IRC said the requirements could expose transmission providers to compliance risks when there is a sudden, unexpected outage or derate of a transmission facility on an ATC path, “as there may not be sufficient time to adjust posted ATC or modify the current interchange schedule in a manner that would completely avoid a violation of the requirement language.” The requirements would also require transmission providers to disregard “expected usage” and account for full reservation capacity granted when calculating firm transmission service transactions. “Treating every firm transmission service reservation as if it is being used in full, regardless of the transmission customer’s scheduling activity, will undoubtedly result in less efficient use of the transmission system,” the IRC said.
BPA said the proposals “address regional seams issues arising primarily in the Eastern Interconnection and are not requirements migrated from the NERC MOD A reliability standards.” It said the rules would require transmission providers and operators to continually balance schedules so that the schedules never exceed the path ratings.
“These standards appear to be inconsistent with how Bonneville and other providers/operators in the Western Interconnection operate their systems,” BPA continued. “For Bonneville and others, an ATC path is allowed to be overscheduled up to 20 minutes prior to flow, at which point interruptions of non-firm service, curtailments or economic dispatches are then performed to ensure path limits are not exceeded. This practice supports the maximum utilization of the transmission system, a key commission objective with respect to transmission, including the integration of variable resources scheduled within the hour. There are many situations that arise which may allow additional schedules or non-firm reservations to stand prior to flow, such as changes in system conditions or the receipt of counterflow schedules.”
BPA said its concern “is particularly relevant in light of the recent heat wave events of August and September 2020 in California, wherein energy supply and transmission availability were severely constrained, which led to energy emergency alerts and ultimately rolling blackouts. Eliminating the practice of overscheduling until 20 minutes [prior to flow] on transmission facilities such as the California-Oregon Intertie … could exacerbate the problem by artificially restricting energy supply and transmission availability even further.”
BPA said eliminating the practice of overscheduling until 20 minutes before flow could limit transmission on facilities such as the California-Oregon Intertie, exacerbating problems that led to rolling blackouts in August.
The IRC said the requirements were included in WEQ-023 even though they were initially rejected by the NAESB Business Practices Subcommittee and opposed in comments by PJM, MISO, SPP, ERCOT and Ontario’s Independent Electricity System Operator.
ATC
In the NOPR, the commission expressed concern that WEQ-023 may lack the transparency and consistency of MOD A, noting that it does not contain replacements for MOD-001-1a requirements R6 and R7, which direct transmission operators to use assumptions no more limiting than those used in its planning of operations calculations.
The commenters were unconcerned. EEI and OATI said the commission should not attempt to address ATC calculations within its regulations and that any additional changes should be considered in the NAESB standard development process.
“By its directives in Order No. 890 and its provisions in the pro forma Open Access Transmission Tariff (OATT), the commission has ensured that the ATC calculation is consistent and nondiscriminatory,” EEI said.
NAESB provides “an open, transparent and industry-participant-driven process” for considering additional rule changes, said OATI, which offers transmission providers software and processes for automation and decision support.
“This fosters a working environment where both transmission providers and transmission customers can come together to discuss solutions to issues that address the unique needs of both parties. This process is then documented for those not in attendance,” OATI said. “In contrast, unilateral alteration of the pro forma OATT lacks the collection of input from impacted industry participants. Without the input from such parties, the commission could unintentionally and unnecessarily burden industry participants with regulatory changes.”
The IRC said WEQ-023 contains “sufficient detail to protect transmission customers and ensure transparent, consistent and non-discriminatory ATC calculations” and increase transparency by requiring transmission providers to document and post their calculation methodologies.
“The WEQ-023 standards reflect an industry-wide consensus on the treatment ATC and TTC [total transfer capability] from a commercial perspective,” BPA said. “There is no need for the commission add additional requirements.”
BPA also said FERC’s proposed language “includes ambiguous references to technical concepts such as using ‘factors derived from operations and planning data’ in the calculation of ATC and TTC.”
If the commission does order NAESB to pursue additional standards, BPA said, it and industry should “avoid conflating commercial and reliability standards. Any further work done by NAESB should be focused strictly on commercial-related standards, whereas NERC should be focused on reliability matters.”
Sequence
FERC also got pushback on whether it should cancel NAESB Version 3.2 and proceed directly to Version 3.3.
“Implementation of the different versions simultaneously are not necessarily simple upgrades,” EEI said. “Additionally, [Open Access Same-Time Information System] updates, training and testing are required for successful implementation.”
OATI said the implementation periods for 3.2 and 3.3 should be “separate and consecutive … to prevent wasted industry effort and cost” because combining the two would force companies to cancel or heavily revise their implementation plans.
“Keeping the Version 3.2 and Version 3.3 separate also decreases the impact to the industry and therefore reduces risk of implementation failure and errors,” OATI said. “The business practices included in Version 3.2 are significant changes to the currently established business practices. The impacts of pre-emption, right of refusal and consolidation affect many aspects of the transmission service procurement and approval process. The fundamental changes begin with transmission customer actions and extend into areas such as line capacity calculations, settlement calculations and billing notification systems. Combining the implementation of Version 3.2 and 3.3 exponentially increases the number of impacts changing in one period.”
The 18-month implementation period for Version 3.3 should begin after implementation of Version 3.2 ends, OATI added.
BPA said FERC should allow at least a 12-month implementation period for Version 003.3, after the final compliance deadline for 003.2.
Parallel Flow Visualization
The IRC asked FERC for an accelerated implementation of rules that it said will improve congestion management in the Eastern Interconnection by incorporating “parallel flow visualization” (PFV) into the transmission loading relief process.
The IRC said PFV, the result of a 14-year industry effort, “will more accurately account for internal flows [i.e., network native load] by incorporating the use of real-time data into relief obligations calculated by the interchange distribution calculator (IDC). Rather than estimating generator output based on load and whether or not units are on outage, the calculation will utilize real-time output and projected next-hour output to calculate native load and network service. This approach is similar to an approach currently used by PJM, MISO and SPP to calculate market flows that was incorporated into the IDC in 2003.”
It asked that the PFV standards be implemented on an expedited timeline, with compliance filings due nine months after the publication of a final rule in the NAESB proceeding and implementation required three months later.
Experts this week said 2020’s impacts on the energy sector will be lasting, predicting a gradual economic recovery but swifter and permanent social transformation.
Utilities’ financial outlooks are steady but fragile as 2020 wanes, panelists said during the final two sessions of Edison Electric Institute’s 55th Financial Conference on Wednesday.
“What’s the saying? May you live in interesting times,” joked Brandon Presley, outgoing president of National Association of Regulatory Utility Commissioners and a member of the Mississippi Public Service Commission. He added that he never thought he would conduct NARUC business from a Mississippi conference room for an entire year.
American Electric Power Executive Vice President Lisa Barton said that in March, her company was already agility testing for telework opportunities when social distancing mandates wiped out office commutes.
Lisa Barton, AEP | EEI
“And we haven’t been back to the office since,” she said.
Leslie Rich, managing director of J.P. Morgan Asset Management, said electric utilities were quick to cut costs after a steep decline in demand in March and April.
She said the question remains on how long lowered demand will persist into 2021 and how regulators will consider that when utilities’ rate cases come before them.
“Revenues are down, sales are down and [operations and maintenance] are down,” Rich said.
Fitch Ratings Senior Director Barbara Chapman agreed that the recession will need to be factored into upcoming rate cases. She said Fitch initially forecasted a quadrupling of bad debt among electric utilities that fortunately did not come to pass. She also said Fitch under-forecasted residential energy demand in the pandemic’s early phases.
“But certainly there’s things on the horizon to give us concern,” Chapman said.
Rich warned that winter will bring the heftiest utility bills, as home and business heating ramps up.
“You don’t want to see customers get buried by their arrearages,” she said, but she added that utilities have been “creative” so far in keeping a steady cash flow.
NARUC remains opposed to a national moratorium on utility shutoffs for the remainder of the pandemic, Presley said.
“State regulators did not have to be prodded by anyone. … Nobody rang our phones and said, ‘You have to step up.’ We did it out of our own volition,” Presley said. “State regulators are on the ground and listening to health and human service departments and wisely making decisions in their respective jurisdictions.”
He also warned that “what works in New York may not work in North Carolina, and what works in North Carolina may not work in North Dakota.”
“The worst thing we could have happened is a fast and loose national policy that wasn’t tailored to constituents. Utilities have to have a heart, not just a head, and regulators have shown that. … But bills do have to get paid.”
Barton said when AEP has lifted shutoff moratoriums, it has been “pleasantly surprised” by customers’ willingness to enroll in payment plans. “It’s often people that have never been in this kind of situation before.”
Chapman said utilities generally want to avoid any “PR nightmares” and the perception of callousness as they resume disconnections.
New York Public Service Commissioner Diane Burman agreed with Presley about a national moratorium, but she warned that customers are incurring balances that they might not be able to pay off.
“We have to realize that there is growing debt on customers not being able to pay these bills,” she said. Regulators and utilities should enact measures such as deferred payment plans and investigate the fallout from shuttered businesses that will never cover their final bills. Their arrears should not be absorbed by other ratepayers, she said.
She also said she has noticed stronger corporate commitment to decarbonization and clean energy, even if the pandemic interrupted steady revenues and some technological breakthroughs. She noted the docket her commission opened in October to consider collecting financial disclosures on climate change-related risks.
Barton said going forward, the grid must be “reinforced” so it can support an onslaught of electrification and make it possible for old generation assets to continue to retire and be replaced by renewable sources.
Rich said more utilities have spun off fossil fuel businesses to become pure-play utilities, both for the revenue and the improved public reception.
Social and Environmental Justice
Racial equity and sustainability had a watershed year, despite the coronavirus, panelists agreed. The pandemic and the police killing of George Floyd amplified a social justice focus for virtually all businesses, the energy sector included.
Fortis CFO Jocelyn Perry | EEI
Fortis CFO Jocelyn Perry said social justice is a relatively new investor expectation. Before this year, Perry said Fortis had focused on gender equality, with a goal of women making up 40% of its board and 33% of its executives.
“But you throw a pandemic and social unrest in this, and we have to broaden more quickly than we thought we had to. … Our customers and our communities are hurting,” she said.
ISS Corporate Solutions Vice President Ben Magarik said an emerging trend is investors voting against or withholding votes on prospective board members. He also said there is increasing pressure on businesses to make disclosures “on a basic level of ethnic or racial diversity” in their workforces.
Jan Childress, Con Ed | EEI
“There’s an enormous amount of uncertainty in the next few weeks, but there’s also a palpable sense of change among investors and businesses,” Magarik said. “I think society’s pretty clear that we’ve got some hard challenges to tackle.”
Consolidated Edison Director of Investor Relations Jan Childress said his company is tracking metrics on diversity and progress on climate change and tying them to executive compensation. He said coupling climate and cultural progress to salaries is necessary for change and “simply opening our eyes to the truth.”
Data tracking on diversity and sustainability has emerged throughout 2020 for electric utilities, Magarik said.
“I risk a cliché, but what gets measured gets managed,” he said.
MISO is sticking with its usual slate of transmission planning studies for next year, opting not to include specially targeted analyses in its annual package.
Project Manager Sandy Boegeman said MISO intends to conduct the usual studies for the 2021 Transmission Expansion Plan (MTEP 21), despite a few specific requests from stakeholders. The grid operator collected ideas for new studies through September. (See MISO Winds down MTEP 20 Planning, Focuses on 2021.)
The Environmental Groups sector requested that MISO conduct two studies examining footprint change if either LG&E and KU or Memphis Light, Gas and Water join the RTO within the next five years.
“MISO does works directly with entities to understand the potential value of joining MISO, as requested by interested entities. Those requests are independent of the MTEP planning cycle,” Boegeman said during a Planning Advisory Committee teleconference Wednesday.
The Environmental sector had also asked that MISO study the three MTEP 21 futures scenarios using $0/MWh hurdle rates with its neighboring regions. The sector said it wants the RTO to better document the use of hurdle rates in MTEP studies.
American Transmission Co. had asked MISO to study short-circuit ratios and analyze the costs and benefits of designing transmission projects to handle multiple needs instead of a singular need.
Boegeman said these requests did not merit independent studies but could be investigated by tweaking modeling assumptions or methodologies in existing MTEP studies. She said MISO will explore accommodating them and discuss them in upcoming Planning Subcommittee meetings.
Stakeholders have tapped former PepsiCo Chief Information Officer Jody Davids to serve on MISO’s Board of Directors, creating a first-ever woman majority for the body.
Davids’ appointment means the nine-member board of independent directors tips to a woman majority for the first time since it was established in 1998. Davids joins female Directors Theresa Wise, Barbara Krumsiek, Nancy Lange and Chair Phyllis Currie.
“Even amidst this most challenging year, MISO continues its commitment to diversity and inclusion — this extends to our staff and board. We recognize that we need diverse voices and experiences to move us forward,” MISO CEO John Bear told RTO Insider. “Ms. Davids brings robust information technology knowledge to help us innovate and adapt to the accelerating changes in our industry.”
Jody Davids | Premier
Members also voted to retain incumbent Directors Wise and Robert Lurie, who are both rounding out their first terms and applied for reappointment. Lurie served the final year of former Director Thomas Rainwater’s term, which expires next month. (See MISO Sets Candidate Slate for Board Elections.)
The three-year terms begin Jan. 1.
The election means veteran Director Baljit Dail will not return to the board’s U-shaped table in 2021. Dail served 12 years on the board — three more than technically allowed — through a special waiver that allowed him to stand an extra term to allow the board to retain a person with technology knowhow.
A technology expertise vacuum among board members is no longer a problem with the entry of Davids, who brings more than three decades of experience managing the technology workings of large companies. She has also served as CIO for Agrium, Best Buy and Cardinal Health, and currently sits on the board for Premier, a Charlotte, N.C.-based health care improvement company. Davids holds an MBA from San Jose State University.
“We are pleased to welcome Jody to the board and excited that Bob and Theresa will continue serving. We thank Bal for his service and wish him continued success,” Currie said in a release. “The diversity of thought and experience has never been more important to the MISO board. As we continue to innovate during these challenging times, we are confident that these leaders will help us continue to move forward.”
Bear said Davids’ experience will complement an already “solid team of leaders” on the board.
“I am honored to be selected and delighted to join the MISO board. As a reliable and affordable grid operator, MISO has already achieved much success. I look forward to contributing to this well respected group of experienced professionals,” Davids said.
The clock is ticking for compliance with NERC’s cybersecurity supply chain risk management standard.
After a three-month delay because of the coronavirus pandemic, CIP-013-1 took effect on Oct. 1, starting the 18-month compliance period for balancing authorities, reliability coordinators, generator owners and operators, transmission owners and operators, and some distribution providers.
The standard, prompted by FERC Order 829 in 2016, requires those registered entities to implement supply chain risk management plans for high- and medium-impact bulk electric system cyber systems.
It also requires them to vet not just third-party suppliers, but also “fourth parties” — the suppliers’ suppliers — to identify any foreign ownership, Dario Lobozzo, Fortress Information Security’s global vice president for supply chain and vulnerability risk, told the Edison Electric Institute’s annual Financial Conference on Tuesday.
Dario Lobozzo, Fortress Information Security | Edison Electric Institute
“How do you accomplish that? It requires a pretty broad set of assessments across all of your different vendors that you buy from as well as [individual] products,” Lobozzo said.
But he cautioned entities “not to boil the ocean” to achieve compliance.
“First you want to get a high-level idea of who’s risky, who’s not risky,” Lobozzo said. “From your 1,000- or 2,000-vendor portfolio, which 50 to 200 of them are really CIP-critical vendors and products that you need to move into the next phase?”
“Onboarding” vendors and performing risk assessments on them “can run a tremendous amount of man-hours, or it can be quite simple,” he said. “It really depends on how responsive the vendors are; how precise the [vendor] questionnaire is. And then you’ll need to map all of that and [transmit the results] to your security team, to your procurement team, to your third-party risk management team.”
If an issue is identified and a vendor promises to remediate it in 90 days, “you’ll need to call them back in 90 days and ask for proof of that remediation,” he continued.
In addition to responding to FERC’s directive, CIP-013-1 builds on President Trump’s May 1 Executive Order 13920 on “Securing the U.S. Bulk-Power System,” which prohibits use on the system of equipment that was designed, developed, manufactured or supplied by companies under the control of jurisdiction of U.S. foreign adversaries.
Asset owners with a service territory including military bases or other government facilities may also be subject to Section 889 of the fiscal year 2019 National Defense Authorization Act, which prohibits U.S. government agencies from entering into some contracts involving telecommunications equipment or services from Chinese entities, Lobozzo said.
Identifying foreign ownership, control or influence (FOCI) is “particularly onerous,” Lobozzo said, requiring identification of corporate families that may have acquired vendors and continuously monitoring each vendor for new foreign ownership.
The need for a centralized repository for all that information is what led Fortress to team with American Electric Power in 2019 to create the Asset to Vendor Network (A2V), which Southern Co. joined in June. Hitachi ABB joined in August. (See Hitachi ABB Joins Supply Chain Security Network.)
Fortress Information Security created the Asset to Vendor Network with AEP in 2019 to improve CIP compliance and reduce costs. Southern Co. and Hitachi ABB are among the companies that have joined. | Fortress Information Security
By taking a “community approach” to compliance, in which members of the network share their assessments with others, the sponsors say they can improve compliance and reduce compliance costs. Assessments are shared at 50% of the original development cost, with contributors earning royalties that allow them to recover a share of their compliance costs.
“Utilities have a long history of working together to overcome challenges and securing our mutual supply chain through A2V is just the latest example,” Tom Wilson, Southern’s chief information security officer, said in a statement when the company joined the network. “A2V offers the opportunity for companies to collaborate and help share expertise and best practices.”
A2V, which has assessed about 350 vendors and products to date, can complete an assessment within three days, compared with three to six weeks under traditional assessments, Lobozzo said.
Fortress polled 150 vendors and found virtually all of them had some kind of security program in place, “which sounds great on the surface, but then when we dove a little bit deeper, we ended up finding that only about 15 to 30% of them actually had a security program that mapped back to a particular standard or that included common best security practices, like multifactor authentication,” Lobozzo said.
Like prior CIP standards, CIP-013-1 is purposely vague, he said. “They’re really designed to help you as an organization implement some forward-thinking,” he said. It is “not prescriptive as to what you need to do but is prescriptive on what you need to accomplish with your actions.”
“If you read between the lines, it’s clear to me that products are a component that could potentially add a risk to the BES,” he said. “As someone who might be audited, you should be concerned that they might point at a particular product, not just a vendor — and say this particular product is exhibiting vulnerabilities that are now known.”
