Page 1017 – RTO Insider

November 15, 2020

Overheard at the 28th NECBC Annual Conference

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.

NECBC 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.

When the governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont released a joint statement in October calling for reforms to States Demand ‘Central Role’ in ISO-NE Market Design.)

“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

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.”

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.”

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.”

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.

NERC CEO Jim Robb is not one of those people.

“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.

“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.

“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.

“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.)

November 15, 2020

PJM IMM Warns Against Another Capacity Market Overhaul

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.

PJM IMM — 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.

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.)

Finally, in the Financial Transmission Rights and Auction Revenue Rights section, the Monitor recommended that PJM enforce the FTR auction bid limits at the parent company level beginning immediately.

November 15, 2020

RTOs, BPA Fear NAESB Rules Will Cut Tx

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.)

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.”

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.

November 13, 2020

EEI Panelists Predict Protracted Economic Recovery

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.

Economic recovery — 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 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.

“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.

November 13, 2020

MISO Rules out Special MTEP 21 Studies

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.

November 13, 2020

PepsiCo ex-CIO Makes 1st Woman Majority on MISO Board

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.”

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.

November 13, 2020

CIP Compliance: Don’t ‘Boil the Ocean’

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.

CIP Compliance — 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.)

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.”

November 13, 2020

Western Utilities Eye RTO Membership in SPP

SPP signaled it could be on the verge of further expanding its RTO footprint with an announcement Thursday that several Western utilities are committed to evaluating membership in its regional electricity market.

Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association and the Western Area Power Administration would become the first SPP members to have facilities in the Western Interconnection under the RTO’s Tariff.

WAPA’s membership would include participation of its Upper Great Plains-West (UGP-West) region and Loveland Area Projects, the RTO said.

The utilities, some already members of SPP in the Eastern Interconnection, have all sent letters expressing their interest in placing their Western facilities under the RTO’s Tariff. The letters indicate they will work with SPP to evaluate the terms, costs and benefits of doing so, the grid operator said.

Tri-State staked out a leadership position within the group, devoting part of a Thursday press conference with Colorado Gov. Jared Polis to extoll the benefits of RTO membership. The virtual event was to highlight Tri-State’s electric resource plan, to be filed with the Colorado Public Utilities Commission next month, that will “dramatically” increase its renewable resources and reduce emissions. Under Polis, Colorado has established a goal of 100% renewable energy by 2040.

Tri-State CEO Duane Highley said connecting the West’s solar capacity with the East’s abundant wind capacity — Kansas and Oklahoma both produce more wind energy than they can use — will efficiently facilitate the transfer of additional generating resources across the regions and offer an opportunity for greater solar resource development.

“The next step for us is to help develop an RTO in the West,” Highley said. “In order to [meet our emission-reduction targets], we know we have to coordinate regionally. We want to do everything we can to accelerate this transition to a regional grid. This doesn’t eliminate any of the other options. … We know we have to improve transmission access.”

SPP’s RTO footprint should it expand into the West | *SPP*

Noting SPP has seen renewable energy account for nearly 80% of its fuel mix at times, Highley said “we’re going to need that same coordination as we build and integrate renewables into a broad region.”

“Enhancing regional markets will lead to additional efficiencies, reliability and more cost savings,” Polis said, echoing Highley. “[RTOs] are really important to support the integrity of a higher level of renewables across a broader geographic area.”

“We’ve enhanced electric reliability while integrating more renewable generation than many in our industry ever thought possible; modernized the grid; built and operated a dependable and economic market; and equitably allocated the costs and revenues associated with these and other services,” SPP CEO Barbara Sugg said in a statement. “What’s more, we’ve done it all while staying true to our collaborative and member-driven business model, and now we’re excited for the opportunity to bring the value of RTO membership to new customers in the West.”

‘Substantial Benefits’

SPP said a Brattle Group study conducted for the RTO found the move would be mutually beneficial and produce $49 million in annual savings for current and new members. Western utilities would receive $25 million a year in adjusted production cost savings and revenue from off-system sales. Members in the Eastern Interconnection would benefit from $24 million in savings because of the market’s expansion, transmission network and generation fleet.

An SPP spokesman said the report would be shared publicly once it has been reviewed by the membership in December.

“We anticipate the benefits of these entities joining our RTO to exceed those quantified in the study,” SPP’s Derek Wingfield said. The study’s scope was limited only to adjusted production cost savings and the value of off-system sales.

“But there are numerous other, substantial benefits of RTO membership as we’ve demonstrated for years in the Eastern Interconnection,” he said. “We at SPP hope the evaluation of full RTO membership leads to even more chances to help Western stakeholders lower energy costs, integrate more renewable energy and modernize the grid.”

Tri-State, Basin Electric, MEAN and WAPA’s UGP-East joined SPP in 2015, along with the rest of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)

The utilities and Deseret are also customers of at least one of SPP’s contract-based Western Energy Services, which includes reliability coordination and its Western Energy Imbalance Service real-time market scheduled to launch in February 2021. SPP’s Western RC service will celebrate its one-year anniversary in December.

Tri-State was part of the Mountain West Transmission Group, a coalition of 10 Western utilities that briefly pursued SPP membership in 2017 and 2018. The effort fell apart when Xcel Energy left the group and later committed to join CAISO’s Energy Imbalance Market. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Tri-State spokesman Mark Stutz said Mountain West’s failure did not end the utility’s “long-term interest in and goal to ultimately participate in a regional transmission organization for our region.”

“Tri-State’s participation in a Western Interconnect RTO is essential to advance our members’ reliability, affordability and clean energy goals,” Stutz said. “While the issues are complex, we remain optimistic that together we are on a path that can capture the full benefits of an organized market in the West.”

SPP’s expansion would add Colorado and Wyoming to the RTO footprint, which would then encompass all or part of 15 states.

November 13, 2020March 9, 2025

NARUC Panel Takes on West’s ‘Surreal Summer’

Rolling blackouts, massive wildfires and extreme heat produced a “surreal summer” in the Western Interconnection that panelists examined during the National Association of Regulatory Utility Commissioners’ annual meeting Wednesday.

The blackouts ordered by CAISO on Aug. 14-15 were not the only extraordinary measures taken to deal with a heat wave that outstripped even normal August highs and sent the temperature in Death Valley to 130 degrees Fahrenheit on Aug. 16.

“This wasn’t just a California event,” said Washington Utilities and Transportation Commissioner Ann Rendahl, who moderated the online panel entitled “Lights Out! Lessons from the West’s Surreal Summer Season.”

Washington UTC Commissioner Ann Rendahl moderated a NARUC panel on the West’s ‘surreal summer.’ | NARUC

“The excessive heat across the Western United States resulted in stress for many balancing authorities due to the high air conditioning demand,” Rendahl said. “WECC identified 18 emergency alerts from balancing authorities across the West between Aug. 14 and Aug. 19. A similar event could have occurred in several areas in the West.”

The summer wildfires that blanketed the West in smoke and shut down power in parts of California and Oregon added to the stress on residents and the grid, she said.

Learning from the summer’s events to avoid future blackouts is vital, Rendahl said.

Other panelists were former FERC Commissioner Cheryl LaFleur, a member of the ISO-NE Board of Directors; Ahmad Faruqui, an energy economist and principal with the Brattle Group; David Geier, COO of San Diego Gas & Electric; and Mark Rothleder, COO of CAISO.

Geier spoke about his utility’s lauded efforts to prevent fires in the past decade, such as grid hardening, weather monitoring and public safety power shutoffs (PSPS) to keep utility equipment from sparking blazes.

Rothleder walked through the findings of a preliminary report on the causes of the August blackouts, including day-ahead forecasting failures, untimely exports and limited transmission to import energy from neighboring states. (See CAISO Says Constrained Tx Contributed to Blackouts.)

Faruqui said the summer’s blackouts and PSPS events reminded him unpleasantly of the Western energy crisis and rolling blackouts of 2000/01. This time, his family had battery backup in their home, but hundreds of thousands of customers lost power and air conditioning amid triple-digit temperatures and thick smoke from wildfires.

“We felt we were living at the edge of darkness,” Faruqui said.

Talking with colleagues around the world, he said, he realized “everyone was watching what was happening in California.”

Spur to Regionalization?

LaFleur said that to prevent future outages, California and other Western states pursuing aggressive decarbonization must work harder to ensure they have adequate resources. Arizona, California, Nevada, New Mexico and Washington have ambitious clean energy goals, with other states expected to follow suit.

Renewable resources are not the problem, LaFleur said. The extreme weather conditions and fires of August argue for more carbon-free energy to stem climate change, she said.

But states switching to large amounts of wind and solar need dispatchable resources for the times when wind and solar drop offline, she said.

“I think part of the issue in California, systemically, has been not enough dispatchable resources at the right time to balance the solar and wind,” LaFleur said. “California has been very decisive about what resources it doesn’t want, but it’s suffered from a pattern of closing resources before the ones that were supposed to replace them were online. That included losing 10,000 MW of gas in recent years, [while] planning on new resources, including large-scale storage that’s not online yet.”

Studies have shown states can substantially decarbonize the grid while retaining gas plants that are infrequently used but available when needed, she said.

The other big issue is who’s in charge of resource adequacy, she said. RA planning can only work with “clear lines of authority and clear handoffs to make sure that whoever has their hand on the switch running the grid has enough energy when they need it.”

California has a “particularly tangled and complex set of responsibilities for making sure there’s enough resources available to keep the lights on,” LaFleur said. The state Energy Commission forecasts long-term demand; the Public Utilities Commission orders yearly procurement; the ISO runs the grid on the resources it is given, with limited backstop purchasing authority; and the legislature dictates what type of resources are acceptable for load-serving entities to buy, she noted.

The agencies and the ISO need to work together better and with FERC to make sure there are adequate resources going forward, she said.

Western regionalization could also help California and other states ensure there’s sufficient energy while pursuing decarbonization, she said. In past years, California lawmakers have considered efforts to change CAISO’s governance structure to allow it to lead a Western RTO, but without success. Other Western states have also resisted the idea. (See Western RTO Proponents Vow to Keep Trying.)

“I hope that this summer’s events are a spur to think about that one again,” LaFleur said.

November 13, 2020

ITC Recounts Derecho Response at NERC Conference

ITC Holdings is used to severe weather, with a 16,000-mile transmission network that faces harsh winters in Minnesota and tornadoes in Oklahoma.

But the derecho that hit ITC’s operations in Iowa on Aug. 10 was a new kind of challenge, forcing the company to seek mutual aid for the first time in its nearly two-decade history, Director of Real-Time Operations Darrel Yohnk told NERC’s eighth annual Monitoring and Situational Awareness Technical Conference on Tuesday.

A derecho packs wind speeds equal to a Level 2 hurricane, but the winds blow in straight lines rather than circling. They can occur in a band of rapidly moving thunderstorms when rain-cooled downbursts reach Earth’s surface and spread horizontally.

“A lot of thunderstorms have [downbursts],” Yohnk explained. “What makes a downburst a derecho is the fact that these downbursts can be self-propagating, and they suck more dry air into the storm, making the winds even stronger.”

The National Weather Service defines a derecho as wind gusts of at least 58 mph that cause a swath of damage of at least 240 miles, “which is just huge,” Yohnk said.

The National Oceanic and Atmospheric Administration said the August storm was the most cos t ly thunde r storm disaster in U.S. history, causing four deaths and an estimated $7.5 billion in damages over a 700-mile path from Iowa to Indiana.

The storm, which carried wind gusts exceeding 100 mph, knocked out more than 1,200 miles of transmission on 144 lines, nearly 20% of ITC’s Midwest network. Almost 800 workers were brought in from other companies to help replace more than 1,000 wooden and steel poles.

The nuclear-fueled Duane Arnold Energy Center near Cedar Rapids, Iowa, lost off-site power for almost a day. The plant got its emergency on-site power running just 11 minutes before losing off-site power, after the loss of four 161-kV, one 115-kV and two 69-kV lines, Yohnk said.

The system “got weak enough that when the [345-kV] Duane Arnold-Hazleton line tripped, the impedance changes on the system were massive. We experienced a power swing event, with the Duane Arnold area swinging against the rest of the [Eastern] Interconnection.”

During the swing, zone 1 relay settings caused the tripping of a 161-kV and two 69-kV lines which created an electrical island of the nuclear plant and some load out of Hiawatha, Iowa. “A few seconds later, the island breaks up further and the remaining [345-kV] Duane Arnold-Hiawatha line tripped and that isolated the plant by itself,” Yohnk said.

The 161-kV Duane Arnold-Hiawatha line exceeded its system operating limit, with flows 9.5% above the short-term emergency rating for 1.4 minutes. “Of course, we were implementing our operating plan to address that. The plant was ramping down as fast as it could, but this storm activity was impacting us faster than … we could get the unit ramped down,” Yohnk said.

ITC, a unit of Fortis, lost more than 900 MW load, with 500,000 customers — 30% of its Iowa customer base — losing power.

The last customers were energized at midday Aug. 18 after eight days, “which was a phenomenal feat for us,” Yohnk said.

Operating During Pandemic

Yohnk and officials from American Electric Power and Florida Power & Light also shared with the conference their experiences in running their grid operations during the coronavirus pandemic.

ITC’s operations control room (OCR) is located in Novi, Mich., 30 miles from Detroit, which in March was one of three COVID-19 hotspots in the U.S., along with New York City and New Orleans.

ITC had a “fairly generic” pandemic plan, Yohnk said. The plan had been “pretty much theoretical because we really haven’t had opportunities to implement it, fortunately, over the years, unlike our transmission system response plan,” which was activated during the derecho.

ITC removed its operations planning and relay performance engineers from the control room and issued a work-from-home order March 16 while soliciting volunteers for sequestration.

It created three “waves” of staffers to provide day/night coverage for the OCR and two groups for the physical security command center, with one group sequestered on-site and the others sequestered at home. ITC contracted for all three floors of a hotel adjacent to its headquarters to house the workers.

The OCR staff worked 14 consecutive 12-hour day or night shifts before being replaced. Operators tried to avoid using the same consoles in consecutive shifts.

Other staff provided “daily life assistance” to the sequestered workers, such as delivering groceries and medical supplies, and caring for pets.

The company also sanitized its backup control center — a facility 35 miles from its primary control center that is normally used for training — in case it was needed.

Being sequestered increased the camaraderie of the groups, Yohnk said. “A lot of times in their normal day to day … they get focused on their own work activities and they don’t interact as much on a personal level. The sequestration did give them the opportunity to do that on a much more frequent basis.”

Phil Hoffer, the manager of emergency management system applications at AEP Transmission, said the company did not implement sequestration but that 13,000 of its 17,000 employees began working from home and will probably do so until at least summer 2021.

Hoffer said workers used levity — sharing favorite pandemic songs and goofy high school pictures of themselves — to keep their spirits up. “I think that really helped our employees and supervisors with the stress they were experiencing as a result of all the changes,” he said.

“For the most part, we’ve actually been more productive out of the office than we were in the office” because of fewer interruptions, Hoffer said. “Now, my group’s a little different because only one of the people on our team has school-age kids at home. I think your ability to get things done would change dramatically if you had three or four or five school-age kids at home.”

Hoffer said the company uses video of all its attendees for its remote meetings. “I think it’s easier to pay attention if you’re on camera,” he said. “We’re trying to find ways to make it more like we’re in a meeting, where you kind of have to pay attention.”

Rob Adams, FPL’s senior director of grid control systems for power delivery, briefed the conference on the tools the utility deployed to stay connected, including Microsoft Teams to facilitate remote communication and collaboration.

FPL also used Klaxoon, an app that helps managers keep staff engaged during remote meetings by allowing them to answer questions via their cellphones. “They enjoyed the idea of reacting to the presentations,” he said.