Page 1045 – RTO Insider

May 1, 2019

EPRI Report Downplays Worst-Case EMP Scenario

By Rich Heidorn Jr.

A utility-funded study has concluded a high-altitude nuclear explosion could cause a multi-state electric outage but not the nationwide, months-long blackout some observers have warned of.

The findings are contained in a three-year study by the Electric Power Research Institute on the impact of a high-altitude electromagnetic pulse (HEMP).

Such an attack could result in a multi-state outage, EPRI acknowledged Tuesday, but it said shielded cables, fiber optics, surge protection, enhanced grounding and modifications to substation control houses could reduce the threat.

Although the report did not provide any cost estimates for the mitigation plans, project manager Randy Horton said through an EPRI spokesman that costs could range from $500,000 to $2 million per substation.

EPRI said it conducted the report “because of the extreme differences in views among experts regarding the potential impacts” of a HEMP caused by the detonation of a nuclear weapon 30 km or more above the earth’s surface.

Under the scenarios evaluated by EPRI, “impacts such as regional disruption or damage to DPRs [digital protective relays] and regional voltage collapse could be experienced,” the researchers said. “Research findings do not support the notion of blackouts encompassing the contiguous United States and lasting for many months to years.”

The report comes little more than a month after President Trump signed an executive ord e r requiring the government to coordinate its efforts on EMPs. The order directs the secretary of Homeland Security and other officials to identify the critical functions and infrastructure systems that could be disrupted by EMPs within 90 days.

Generation not Studied

EPRI’s report, which incorporated research from the Department of Energy’s national labs and collaboration with the Defense Threat Reduction Agency and the Electricity Subsector Coordinating Council (ESCC), was funded by some 60 utilities.

It focused on the potential impacts of a HEMP attack on the transmission system and how overhead transmission lines, substations and switchyards could be hardened. It did not look at the potential effects of HEMP attacks on “generation facilities, nuclear reactors, distribution systems, loads or other key elements or infrastructure sectors,” EPRI said, recommending those subjects for further research.

The study looked at the impacts of three “hazard fields” that can be produced by a nuclear detonation, based on the weapon’s yield and the height of the explosion above the surface:

The early time component (E1 EMP), an intense, short-duration electromagnetic pulse characterized by a “rise time” of 2.5 nanoseconds and amplitude of up to 50 kV/meter on the ground;
The intermediate time component (E2 EMP), an extension of the E1 EMP with an electric field pulse amplitude of about of 0.1 kV/m and a length of one microsecond to about ten milliseconds;
The late time component (E3 EMP), a very low frequency (below 1 Hz) pulse with amplitude of tens of V/km lasting from one second to hundreds of seconds. The event would be similar to severe geomagnetic disturbances (GMDs) caused by solar flares, which can last several days.

The area exposed to E1 EMP fields would be limited by the line of sight from the weapon to the horizon; a detonation at 200 km could affect a circular area of 3 million square miles — most of the continental U.S. and portions of Canada and Mexico — albeit at different levels of severity. The pulse can “couple” to overhead lines and cables, exposing connected equipment to voltage and current surges, potentially damaging DPRs, communication systems and supervisory control and data acquisition (SCADA) systems.

EPRI said E1 EMPs would cause “moderate” damage based on modeling from Los Alamos National Laboratory of up to 25 kV/m at the most severe location on the ground. Increasing the pulse to 50 kV/m resulted in “more severe” damage.

Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | *Electric Power Research Institute*

“Based on the assumptions made in the assessments, it was estimated that approximately 5% of the transmission line terminals in a given interconnection could have a DPR that is disrupted or damaged by the nominal E1 EMP environment that was simulated, whereas approximately 15% could be impacted by the scaled (up to 50 kV/m at the most severe location on the ground) E1 EMP environment,” the report said.

Although its testing did not indicate E1 EMP impacts alone would cause immediate, interconnection-scale disruptions, “this finding is not conclusive due to uncertainties regarding how damaged DPRs might respond during an actual event … or how potential E1 EMP damage to generator controls and other systems such as automatic generation control (AGC), not included as a part of this study, might affect the long-term operation of the grid,” EPRI said.

Mitigation Measures

The researchers said their modeling and laboratory testing of DPRs indicated design changes could provide adequate mitigation up to 50 kV/m:

Shielded control and signal cables with proper grounding;
Low-voltage surge protection devices or filters;
Use of fiber optics-based protection and control systems;
Modifications to substation control houses to enhance their electromagnetic shielding; and
Grounding and bonding enhancements.

It also recommended transmission operators maintain supplies of replacement DPRs and other critical assets.

E2 EMPs can couple to overhead lines or cables through the air, like E1 EMPs. “This coupling mechanism is similar to how the field created by a nearby lightning strike couples to an overhead transmission line,” EPRI said. But because of the low amplitude, they are unlikely to affect the transmission system. “Thus, no specific mitigation options were identified as a part of this research,” EPRI said.

Maps of the instantaneous geoelectric field magnitude of an E3 EMP at 20, 40 and 100 seconds | *Electric Power Research Institute*

The low-frequency geomagnetically induced currents (GICs) resulting from E3 EMPs can cause magnetic saturation of transformer cores, causing transformers to generate harmonic currents, absorb reactive power and experience heating in windings and structural parts. “Potential impacts of E3 EMP on the bulk power system can include voltage collapse (regional blackout) and transformer damage due to additional hotspot heating,” EPRI said.But it said E2 EMPs “may be a threat for assets that operate at lower voltages (e.g., low-voltage inverters connected to rooftop PV).”

EPRI said E3 EMPs alone could result in a multi-state blackout, “but immediate, widespread transformer damage due to hotspot heating from part-cycle saturation is not expected to occur.”

Researchers said mitigation options used for GMD events would also be effective for E3 EMPs, including:

Preventing protection system misoperations by modifying protection and control schemes to make them resilient to harmonics and system imbalance;
Blocking or reducing the flow of GICs;
Automatic removal of some shunt reactive power compensation devices such as shunt reactors and use of under-voltage load shedding (UVLS); and
Maintaining supplies of spare large power transformers and high-voltage circuit breakers.

EPRI’s analysis of the combined effect of E1 and E3 EMPs indicated DPRs damaged by surges would not cause the immediate disconnection of transmission lines but would prevent the DPRs from performing their protection and control function.

“Significant damage to DPRs and other controls from E1 EMP would be expected to degrade recovery efforts and longer-term viability of controlling system frequency due to potential damage to AGC and other ancillary functions,” EPRI said. “These latter effects could impact the long-term stability (voltage and/or frequency) of an area affected by the HEMP attack.”

Without hardening of the transmission system, “recovering from a HEMP-induced blackout may present operators with challenges that have not been experienced following previous blackouts from more traditional causes. These potential challenges are primarily related to unavailable, inoperable or damaged equipment and impaired situational awareness capability,” EPRI said.

Recovery Efforts

The study recommended transmission operators develop alternatives to their current step-by-step facility energization procedures, noting damaged equipment may interrupt cranking paths following a HEMP event.

“Because damage to large power transformers is expected to be minimal, recovery times following a HEMP-induced blackout would be expected to be commensurate with historical large-scale blackouts if robust E1 EMP protections are deployed such that E1 EMP impacts to equipment, situational awareness, SCADA and other infrastructures that support power system restoration are minimal,” it said.

Southern Co. CEO Thomas A. Fanning, co-chair of the ESCC, said the report “greatly enhances our understanding of the potential impacts EMPs could have on our national energy grid.”

Scott Aaronson, the Edison Electric Institute’s vice president for security and preparedness, said the report “enables electric companies to make science-informed decisions for developing, testing and deploying EMP-resistant grid components.”

Illustration of an substation control house hardened against an E1 EMP | *Electric Power Research Institute*

“EPRI also tested mitigation strategies and was able to rule out options that don’t work,” Aaronson added. “Multiple electric companies will be piloting those potential solutions to ensure new mitigation strategies do not impact other energy grid equipment or undermine or conflict with mitigation and protective measures that already are in place.”

The report said field testing of mitigation will be needed to avoid unintended consequences and obtain “realistic cost data to inform future decision making.” EPRI said it has begun a new research effort to further evaluate the mitigation options.

Dissenting View

The Secure the Grid Coalition, which claims to have former CIA Director R. James Woolsey among its members, issued a state m ent blasting the EPRI report as a whitewash “reminiscent of past tobacco industry-underwritten efforts to have putatively independent ‘scientists’ disinform the public about the actual dangers of smoking.”

The group said EPRI made “faulty assumptions” about the damage EMPs would cause to transformers and SCADA systems and ignored “abundant data derived by the Pentagon, civilian agencies and government-sponsored studies.”

April 29, 2019

Pennsylvania Joins US Climate Alliance

By Christen Smith

Pennsylvania joined the U.S. Climate Alliance this week after releasing its own action plan to achieve a 26% reduction in statewide greenhouse gas emissions by 2025.

The alliance was established in 2017 after President Trump withdrew the U.S. from the Paris Agreement, a global initiative to limit the increase in global temperature to below 2 degrees Celsius above pre-industrial levels. Since then, 24 states — including six in PJM — have supported the alliance’s efforts to implement environmental policies that target carbon emissions and promote use of clean energy resources.

Gov. Tom Wolf made Pennsylvania the 24th state to join the U.S. Climate Alliance on Monday.

“With the federal government turning its back on science and the environment, I am proud to join with states that are leading the way towards new climate solutions and taking concrete actions to reduce greenhouse gas emissions,” Pennsylvania Gov. Tom Wolf said in a statement. “States like Pennsylvania must take action to reduce greenhouse gas emissions and protect our communities, economies, infrastructures and environments from the risks of a warming climate.”

In January, Wolf signed an executive order committing the state to reducing its GHG emissions by 26% over the next seven years compared to 2005 levels and setting an additional target of 80% by 2050. On Monday, the administration released a third update to the state’s decade-old Climate Action Plan that identified 15 steps capable of reducing carbon emissions by 21% by 2025, including investing in renewable energy resources, boosting the use of electric vehicles and incentivizing green building projects.

“Perhaps the biggest recommendation of the Climate Action Plan is that a team effort is needed to reduce greenhouse gas emissions in Pennsylvania,” Department of Environmental Protection Secretary Patrick McDonnell said. “Government leaders must lead by example, and businesses, farms, community organizations and citizens can all make a difference to fight climate change.”

Julie Cerqueira, executive director of the alliance, applauded Wolf’s proactive approach to climate change and said, “We look forward to supporting the governor’s wide range of climate priorities like promoting solar energy and decarbonizing its power grid while creating new, good jobs in the clean energy industry.”

‘Small Window’

Wolf’s announcement coincides with the introduction of two bills designed to increase targets for renewables in the state’s Alternative Energy Portfolio Standards (AEPS) law. The 2004 mandate requires electricity providers to buy 18% of their power from 16 renewable resources divided among two “tiers” by 2021.

State Rep. Carolyn Comitta (D) and Sen. Art Haywood (D) sponsored companion proposals, House Bill 1195 and Senate Bill 600, earlier this month that would boost the usage requirement of Tier 1 renewable resources from 8% to 30% by 2030. The plans also dedicate 7.5% of that target to in-state grid-scale solar and 2.5% to distributed solar generation, and asks the Public Utility Commission to study the benefits of an energy storage program.

“I am proud to join the calls for modernizing the Alternative Energy Portfolio Standards,” Comitta said on April 17. “Our state has already made important investments in alternative and clean-energy technologies, but we must do more. Adjusting our electrical energy requirements to 30% by 2030 will solidify our path to reducing our carbon footprint and advance Pennsylvania toward becoming a national energy leader.”

The Clean Power PA Coalition threw its support behind the bills in a statement on Thursday and urged legislators to support proposals to limit carbon emissions.

“Scientists tell us we have a small window of time left in order to prevent the most catastrophic impacts of climate change beyond the dangerous impacts we are already experiencing,” the coalition said. “With leadership from Gov. Wolf and the General Assembly, we can build on the strong commitments that have already been made and couple them with equally strong policies that will create jobs and keep our families healthy.”

Meanwhile, state Republicans lead discussions on another plan to prop up aging nuclear reactors with subsidies from a newly created third tier in the AEPS. The House Consumer Protection Committee met for a third time on Monday to discuss the merits of House Bill 11 with executives from across the energy industry, where divisions between nuclear power and fossil fuels run deep. (See Nuke Talks Continue in Pa. Assembly.)

It’s unclear if the legislature will pass HB 11 — or the similar SB 510 (See Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill) — before Exelon begins shuttering Three Mile Island in June. While the state’s action plan calls for policies that would keep TMI and the state’s four other nuclear facilities from closing down, Wolf has not yet signaled support for either bill.

April 29, 2019

FERC OKs NERC Violation Settlements

By Rich Heidorn Jr.

FERC last week accepted settlements with Duquesne Light Co. and an unnamed municipal utility in the Western Electricity Coordinating Council for violations of NERC reliability standards. The commission filed a notice Friday that it would not review the penalties, leaving NERC’s settlements intact (NP19-6).

NERC reported the settlements in a spreadsheet notice of penalty on March 28.

$40,000 Penalty for Duquesne Light

Duquesne agreed to a $40,000 penalty for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6.

The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.

The violation extended for more than two years because Duquesne “lacked an effective verification control” to quickly detect and correct the error, NERC said. The company alerted regional entity ReliabilityFirst of the problem in a self-report in August 2017, after completing its mitigation plan.

NERC said the violation did not indicate a systemic issue with Duquesne’s FAC-008 program because only about 3% of the company’s bulk electric system (BES) transmission facilities were affected.

NERC determined the violation posed a moderate risk and could lead to equipment failure. “The risk is increased because of the long multiyear duration of the violation, but the risk is lessened (and not serious) because only one of the incorrect substation conductor ratings [was] the most limiting factor for these facilities,” NERC said. “The changes that did result in a facility ratings change did not impact the load dump ratings at any ambient temperature set but did impact the normal and emergency ratings.”

The second violation, involving the Clairton‐West Mifflin 138-kV circuit, was discovered during a compliance audit in December 2017. NERC said a section of overhead stranded conductor was not shown in Duquesne’s circuit map. After updating the map, Duquesne conducted a new analysis that resulted in reducing the summer 95 degrees Fahrenheit continuous rating from 932 amperes to 919 amperes.

The violation resulted in ratings reductions for three of Duquesne’s 85 BES transmission circuits (4%).

Although the incorrect ratings were in place for more than three years, NERC characterized the risk as minor “because the change in rating on the 138-kV circuit was minimal: just 13 amperes.”

NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.

Muni Lacked Familiarity with NERC Standards

FERC also chose not to review NERC’s settlement with an unnamed municipal utility over six violations of critical infrastructure protection (CIP) standards. NERC redacted some details of the violations and the utility’s name to protect critical energy/electric infrastructure information (CEII).

NERC’s filing said the utility:

Mischaracterized cyber systems at a substation as low-impact BES cyber systems (LIBCS) that should have been considered medium-impact BES cyber systems (MIBCS). An incorrect analysis found the systems connected to only two other substations when they were actually connected to four other transmission assets and had ties to two different entities, NERC said.
Failed to eliminate unneeded network accessible ports from an engineering workstation in a data center.
Failed to conduct an adequate security patch management program, including a requirement to check for new security patches every 35 days. NERC cited the entity’s “lack of knowledge and understanding of CIP standards.”
Gave five employees electronic or unescorted physical access to its MIBCS without having completed access request forms.
Failed to identify in its baseline configuration all of its network accessible ports and security patches applied to assets.
Failed to perform required change management activities for BES assets, electronic access control monitoring systems and physical access control systems.
Failed to provide evidence that it removed the ability of employees to access its systems within 24 hours of a termination.

NERC imposed no financial penalties for the violations and said none of them posed a “serious or substantial risk” to the reliability of the BES. The entity is a “very small municipal power company that employs few staff and has an extremely low turnover,” NERC said.

April 29, 2019November 29, 2023

ERCOT Briefs: Week of April 22, 2019

AUSTIN, Texas — ERCOT Generators Upset over Early March Weather Event.)

Staff are currently drafting three Nodal Protocol revision requests (NPRRs) with the hopes of presenting them to the Technical Advisory Committee in May.

During a Wednesday workshop on outage activity related to ERCOT’s operating condition notice (OCN) ahead of the event, Luminant’s Ian Haley shared a proposal for an “outage reliability unit commitment” (ORUC) process — though the name is up for debate. Units subject to the ORUC wouldn’t be allowed to self-commit, giving the market 24 hours to “perform.”

Under the proposal, ERCOT would provide 24-hour notice that it will run ORUC, along with a time frame and reliability justification. Units would be committed by the hourly and day-ahead RUC processes during the outage delay period and settled with a make-whole payment floor.

The goal is to optimize outages, Haley said. “If you’re ORUC’ed, think of it as [a reliability-must-run agreement] for capacity,” he said.

Luminant’s ORUC process would be incorporated into NPRR930, which includes a pricing make-whole payment. The change requires ERCOT to use a weekly RUC that can commit resources with an approved outage. Committed units would be made whole with respect to the actual costs and cancellation of the outage. The NPRR also sets an offer floor for the resource at the systemwide offer cap.

“There are still outstanding questions, but I didn’t really feel I lost the room,” Haley said. “If we get into this situation again, we should all be able to look into the protocols and see how this will work.”

ERCOT Senior Director of System Operations Dan Woodfin said the ORUC process could also be a sub-routine within NPRR934, which creates a new OCN type — an advance action notice — that alerts qualified scheduling entities and transmission service providers to modify their outage plans.

Staff is also developing NPRR 935, which would require ERCOT to post wind and solar forecasts and indicate which model is being used for each of the forecasts. Market participants complained about a lack of transparency into which forecasts were being used in late February before the event.

“We know ERCOT will develop more forecasts, so I’d like [the NPRR] to say all forecasts are published,” Citigroup Energy’s Eric Goff said.

“We’re posting the information, but I can’t make anyone drink the water,” Woodfin said. “We’ll go back and look to see if there’s a mechanism to build more flexibility into the OCN process.”

ERCOT has scheduled a second workshop on the OCN issue for this Wednesday in order to stay on track for presenting the information to the TAC during its May 22 meeting. The workshop will take the place of an urgent Protocol Revision Subcommittee meeting that was to take up OCN issues. The PRS will meet as regularly scheduled on May 9.

Workshops Discuss Storage, Inverter-based Resources

The OCN workshop was just one of three held in Austin last week. Warren Lasher, ERCOT’s senior director of system planning, opened an April 23 standing room-only workshop on energy storage by saying, “It’s a great day.

“We get to talk about and identify issues, and talk about who fixes those issues,” he said. “We don’t have to solve them here.”

Lasher said energy storage is a growing resource in the ERCOT market, with about 100 MW available now and an additional 70 MW expected before summer begins. He said another 3 GW, “maybe more,” of energy storage is under study in the interconnection queue.

ERCOT sees batteries as “limited duration” resources that can charge from the grid or discharge onto it. Attendees heard presentations from staff and from E.ON Climate & Renewables North America’s Andrea Bianco, who explained the various available storage technologies.

Discussion topics included how to address hybrid units, communicating resource status and desired operational constraints, reliability requirements, outage evaluation topics, and storage resources’ bids and offers.

The storage workshop served as a lead-in to a Wednesday workshop on transmission-connected inverter-based resources. That workshop’s agenda was highly technical and designed for transmission service providers, resource entities and their vendors.

— Tom Kleckner

April 29, 2019

PJM MRC/MC Briefs: April 25, 2019

Denise Foster Takes over as MRC Chair

VALLEY FORGE, Pa. — Denise Foster, PJM’s vice president of state and members services, chaired her first Markets and Reliability Committee meeting on Thursday, replacing retired CFO Suzanne Daugherty.

Foster came to PJM not once, but twice throughout her two-decade career as an attorney and consumer advocate: first in 2000 as counsel and regulatory affairs manager, and again in 2009 as her current role managing members services, a position that has evolved as PJM’s membership has swelled.

Foster prides herself on building relationships and encouraging positive discourse. “I want to ensure that everyone’s voice is heard, and that the information needed is presented and discussed so good decisions may be made,” she said in a PJM press rel e ase April 23. “We are first, people, and second, business representatives.”

Load Interests Block FTR Rule Changes

The Electric Distributor and End-Use Customer sectors blocked a proposed revision to PJM’s rules about when financial transmission rights profits should be forfeited.

All but one of the voting members in both sectors rejected the joint plan developed by Exelon, NextEra Energy and VECO Power Trading and approved by stakeholders at the Market Implementation Committee in November. The proposal would replace the RTO’s existing “penny test” for a threshold of FTR flows of 10% or more across a constraint.

PJM’s Markets and Reliability Committee meets in Valley Forge, Pa., on April 25. | © *RTO Insider*

“Stakeholders like Exelon have stopped participating both in virtual activity and FTR markets [at the same time] because existing rules are over burdensome,” said Sharon Midgley, director of wholesale market development for Exelon. “The current FTR forfeiture rule is too restrictive for competitive suppliers, prevents legitimate business activities and increases costs to customers.”

“We’re a large load-serving entity,” Exelon’s Jason Barker added. “This is increasing risk premiums. It’s another example of over-mitigation in PJM’s markets.”

Stakeholders deferred a vote on the plan at the December MRC after some expressed fear it could unintentionally create exploitable market loopholes. (See “FTR Forfeiture Rule Deferred,” PJM MRC/MC Briefs: Dec. 20. 2019.)

The Independent Market Monitor also expressed reservations about changing the status quo. It has argued that the penny test is better at catching manipulative behavior. (See “FTR Forfeiture Proposal Endorsed,” PJM MIC Briefs: Nov. 7, 2018.)

A second FTR rule change that would adjust calculations to account for on-peak and off-peak FTRs was endorsed by acclimation. (See “First Read on Change to FTR Forfeiture Calculations,” PJM MIC Briefs: March 6, 2019.)

Carbon Pricing Talks Move Forward

PJM will soon assemble a task force dedicated to studying the impacts of carbon pricing throughout the RTO’s 13-state footprint.

Stakeholders approved the problem statement and issue charge in a sector-weighted vote of 3.92 to 1.08 on Thursday. The new group will report findings to the MRC over the next 18 months.

“I think it’s important to get the ball rolling, but this isn’t a fast-track item,” said Michael Borgatti of Gabel Associates.

Borgatti presented a first read of the problem statement and issue charge at the March 21 MRC that would task stakeholders with creating rules to address carbon leakage and help states meet greenhouse gas reduction policies. Borgatti made the presentation on behalf of the Independent Energy Producers of New Jersey, which includes NextEra and PSEG Power.

Dana Horton, of American Electric Power, and Chuck Dugan, of East Kentucky Power Cooperative, two utilities with substantial coal-fired generation, opposed the initiative.

“If we were talking about a nationwide carbon adder, we’d be all in,” said Horton, who said he feared the initiative could lead to higher prices for AEP customers in states that have not joined Illinois and New Jersey in approving nuclear subsidies. “But we disagree that this is the right time to do this.”

Dugan echoed Horton’s sentiments. “We’re a state that’s a coal state,” he said. A carbon adder “is not required, and we are very busy in the stakeholder process [with other issues]. We should hold off.”

Marji Philips of Direct Energy, however, said Borgatti’s proposal is the “best solution to deal with externalities that the states say PJM is not dealing with.”

“Ohio’s going to have a [zero-emission credit] program soon if their utilities have their way,” she added, referring to legislation under debate in the state legislature.

RTEP Removal Language Vote Deferred, Again

After a bit of procedural skirmishing, members agreed to delay a vote on LS Power’s proposal to amend Manual 14B for another 60 days while stakeholders continue talks about the intersection of supplemental and regional project planning.

Sharon Segner, vice president of LS Power, offered the revisions at the January MRC after expressing concern over the growing number of supplemental projects languishing in the Regional Transmission Expansion Plan. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria.

Segner’s proposed language specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. A special session of the Planning Committee has been meeting over the last 60 days to review a variety of legal issues related to FERC Orders 890 and 1000 — meetings that PJM staff said are narrowing their differences. (See “LS Power will Seek 2nd Deferral on Transmission Replacement Language,” PJM PC/TEAC Briefs: April 11, 2019.)

When Segner presented specific topics for the special PC session to discuss during the deferral period — including possible Operating Agreement revisions — Chair Foster intervened.

“Adding all these items to the discussion that has been assigned to the lower committee is out of order,” she said. “The expansion [into OA revisions] is what I particularly take issue with.”

Segner argued against Foster’s interpretation of committee rules, noting that any revisions to rules relating to Order 1000 need inclusion in the OA, per FERC precedent. After nearly an hour of debate with other stakeholders about the appropriate scope of the motion, she agreed to proceed with only the 60-day deferral.

“I request in the minutes for today it is specifically outlined that in 60 days, when this issue comes back before the MRC, if a friendly amendment that reflects OA language that is germane to the main motion is offered, I may deem it as friendly,” Segner said.

– Christen Smith

April 29, 2019

California Regulators Weigh PGE’s Fate

By Hudson Sangree

The California Public Utilities Commission hosted a forum Friday where some experts urged it to break up Pacific Gas and Electric despite the challenges attending that move, while others favored keeping the troubled utility intact.

Whatever the outcome, PUC President Michael Picker said, the solution is likely to seem as bad as the problem to many people.

“It’s not a question of ‘out of the frying pan and into the fire,’” Picker said. “It’s ‘which fire are we going to pick?’”

Friday’s forum was the second in a series of public meetings on PG&E held by the PUC.

Most of the homes in Paradise were gutted by the Camp Fire, the deadliest in California history. | © *RTO Insider*

State regulators and other authorities have been discussing PG&E’s future with greater urgency since it filed for Chapter 11 bankruptcy reorganization Jan. 29. The utility cited billions of dollars in potential wildfire liability for its bankruptcy and said it might seek to rescind hundreds of costly power purchase agreements entered into when prices for renewable energy were higher than they are today. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)

Recent disasters blamed on PG&E have increased public and political antipathy toward the 114-year-old utility, headquartered in San Francisco.

State investigators have concluded PG&E equipment started wildfires that killed at least 22 people in 2017 and 2018. Not included in that total is the Camp Fire, the deadliest in state history, which killed 85 residents and destroyed most of Paradise, a town of 27,000 in the Sierra Nevada Foothills. Investigators have yet to determine the cause of the fire, but PG&E said its equipment is likely to blame.

After “so much death and destruction,” the utility faces an unprecedented turning point, said David J. Hayes, executive director of the State Energy & Environmental Impact Center at the New York University School of Law. “You’re never going to have a time, I think, when the public is more supportive of extraordinary steps than you have right now,” he told PUC commissioners.

Hayes and others suggested that breaking up PG&E into smaller entities could accomplish several goals, including reducing the risk of cyberattacks. If attackers took down PG&E, it would eliminate gas and electric service for much of California, he noted. But “the system becomes more resilient” if PG&E is separated into smaller units, he said.

‘Culture of Entitlement’

The arbiters of PG&E’s fate go beyond the PUC. They currently include a federal bankruptcy judge and another federal judge overseeing PG&E’s criminal probation in the 2010 San Bruno gas pipeline explosion that killed eight residents of a suburban San Francisco neighborhood. (See Federal Judge to Review PG&E’s Wildfire Plan.)

Gov. Gavin Newsom, state lawmakers and the state attorney general’s office have weighed in. (See Calif. Must Limit Wildfire Liability, Governor Says.) So has FERC, along with ratepayer advocates, fire victims and generators that sell electricity to PG&E. (See Judge Puts Off Decision in PG&E v. FERC.) The FBI is helping local authorities conduct a criminal investigation of PG&E’s involvement in the Camp Fire, according to some news reports.

At stake in all this activity is the future of the state’s largest utility, which supplies electricity and gas to 16 million residents across 70,000 square miles of Northern and Central California, or about 42% of the state.

PG&E’s critics contend the public’s safety hangs in the balance, and that the utility’s finances must not take precedence. The utility is irredeemably flawed, some say.

“No amount of incentives, CEO compensation or board member replacement can fix a company infected with a culture of entitlement,” said Scott Hempling, a regulatory adviser and adjunct professor at Georgetown University Law Center.

PG&E believes it’s entitled “to remain the monopoly franchisee indefinitely, no matter how many rules you break, how much evidence you hide, how many felonies you commit [or] how much damage you do,” Hempling told the PUC.

To stand up to PG&E, state officials must be ready to adopt alternatives to the monopoly, investor-owned utility, he said. “We need to show that ‘too big to fail’ is a myth.”

A senior citizens community in Paradise, Calif., was destroyed by the Camp Fire in November. PG&E has said its equipment was likely to blame for the fire that killed 85 people. | © *RTO Insider*

PG&E insists it’s taking safety concerns seriously and trying to change. It announced plans this month to install a new chief executive and 11 new board members out of 13, touting the new members’ utility and safety experience. (See Former FERC Commissioner Brownell Named PG&E Chair.)

On April 22, however, PG&E provoked more public outrage by asking the PUC to increase its return on equity — a major source of profits — from 10.25% to 16% to help pay for $28 billion in fire safety and other upgrades over the next four years. (Southern California Edison, also blamed for deadly wildfires, recently requested that FERC approve a higher ROE for safety-related transmission line investments.)

“PG&E is proposing a $1.2 billion increase in its currently approved cost of capital, based on a 16% return on equity,” the utility said in a news release. The proposed increase is meant to ensure access to capital markets and would raise an average customer’s electricity bill by about 7%, it said.

“Investors must continue to play a vital role in providing the capital necessary to fund essential safety and reliability infrastructure upgrades,” CFO Jason Wells said in the statement. “These investments allow PG&E to offset the upfront, immediate costs of these long-term projects to our customers.”

Travis Kavulla, director of energy and environmental policy at the R Street Institute, a D.C. think tank, and a member of the Western Energy Imbalance Market’s Governing Body, said the applications for higher returns on equity filed by PG&E and SCE would base a quarter to a third of the companies’ future profits on predicted fire liabilities.

The utilities, especially PG&E, “have already made in essence an opening bid to say what amount of their profit is guided by wildfire-related risk,” Kavulla said. Instead, he said, profits should be connected to measurable results.

“A significant amount of this firm’s profits … should be tied explicitly to achievement of safety outcomes rather than simply being earned as a return paid on capital investments,” Kavulla said.

IOU vs. POU

In the debate about breaking up PG&E, Bere Lindley, assistant general manager of the South San Joaquin Irrigation District, a publicly owned utility, said it would make sense for some areas of PG&E’s territory to become municipal utilities. Publicly owned utilities (POUs) are governed by elected officials and responsible to customers, not shareholders, he said.

POUs have been shown, on average, to lower rates and increase reliability, he argued.

“Customers, owners and the public are the same people in the POU model. They have the same interests,” Lindley said. “The POU structure provides an elegantly simple solution to align natural stakeholder interests for a monopoly business.”

The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District (SMUD) and 39 other public entities provide electric service in California. LADWP — the largest POU in the country — has 3.9 million customers; the smallest POUs serve fewer than 400 residents, according to the California Energy Commission.

Currently, only San Francisco, one of the nation’s wealthiest cities, is seriously considering acquiring PG&E’s equipment and forming a municipal utility, Commissioner Martha Guzman Aceves said. Other communities would likely lack the means, she said, leading to disparities in electric service based on wealth.

Businesses in Pardise, including the town’s McDonald’s restaurant, were ravaged by the Camp Fire. | © *RTO Insider*

Susan Mac Cormac, a partner at corporate law firm Morrison & Foerster, moderated the panel. She said municipal utilities don’t have the resources to cover the billions of dollars in capital expenditures that PG&E likely faces to upgrade its infrastructure and cover wildfire costs. She recommended keeping the utility intact.

John Di Stasio, president of the Large Public Power Council and former CEO of SMUD, said municipal utilities often have top credit ratings and access to capital. Still, he acknowledged, local governments would face significant challenges in trying to take over from PG&E. SMUD faced difficult hurdles in attempting to annex outlying areas of Sacramento from the utility.

“This is a significant hill to climb,” he said.

One example of those challenges came from Sam Weaver, the mayor pro tempore of Boulder, Colo., who participated in the PUC forum by telephone.

Boulder has spent years battling Xcel Energy, the large IOU that serves the city, to take over its poles and lines and create a municipal utility. The results of that effort remain uncertain, and Boulder will likely pursue condemnation proceedings, Weaver said.

Even if Boulder’s municipalization effort ultimately fails, it may still achieve positive results in terms of rates and quality of service, he said.

Xcel committed in December to providing its customers with carbon-free energy by 2050, becoming the first large IOU to make such a pledge. The move was likely a response to Boulder’s pledge to provide all-renewable energy by 2030 if it created its own utility. (See Xcel Pledges to Go 100% Carbon Free.)

“It applies pressure to the [investor-owned] utility because you establish yourself as a customer, and not just as a captive ratepayer,” Weaver said.

April 29, 2019

MISO Seeking Proposals to Relieve North-South Constraint

By Amanda Durish Cook

CARMEL, Ind. — MISO is accepting proposals for projects designed to relieve its increasingly costly North-South transmission constraint, but it is still zeroing in on an approach to evaluate submissions.

During a Thursday conference call to inform stakeholders about MISO’s expectations of design parameters, staff expressed hope that a viable candidate could emerge from a second round of proposals to relieve the constraint given recent changes to the RTO’s own outlook and the way it values the monetary benefits of large transmission projects.

The submission window for proposals will remain open until June 21. Once ideas are submitted, MISO will perform screening analyses through July to identify possible candidates. After performing more in-depth analysis and cost estimates, the RTO could announce a viable candidate by August.

MISO has added the Midwest-South interface as a constraint to be evaluated under its ongoing Market Congestion Planning Study (MCPS). (See MISO Takes Second Look at North-South Constraint.) Planning Manager Matt Ellis said the constraint was added at stakeholder request.

Ellis said the second look comes as MISO seeks to add a new benefit metric for market efficiency projects that reduce the costs of its settlement with MISO MEP Cost Allocation Plan Goes to FERC.) Ellis said the new metric could render some project candidates more beneficial than they appeared when MISO last studied the constraint in 2017.

The transfer constraints between MISO’s Midwest and South regions contributed to the RTO’s September and January emergency events, CEO John Bear said at an April 23 Informational Forum. He said MISO had adequate resources during both emergencies, but transmission constraints kept it from accessing them to relieve emergency conditions. He said a project could strengthen the RTO’s greatest asset: its footprint diversity. (See MISO Claims up to $3.9B in 2018 Benefits.)

Under the MISO-SPP settlement agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity usage factor. Beginning next February, that amount is subject to a 2 to 4% escalation rate, depending on use.

“Fifteen years out, those payments could get pretty high,” Principal Transmission Planning Engineer Shane O’Brien told stakeholders.

O’Brien also said the agreement itself will soon be less certain. Starting Jan. 31, 2021, it may be terminated by any party with a year’s notice. Without a replacement settlement in place, flows would be limited to MISO’s original contract path.

“We could potentially have to revert back to 1,000 MW in the earlier direction,” O’Brien said.

MISO has also said that growing renewable use is set to increase flows on the contract path. By 2033, the RTO has fo u n d that interface flows could reach 8,000 MW north to south based on data from its Transmission Expansion Plan (MTEP) futures. Using the accelerated fleet change MTEP future, MISO estimates that its annual settlement payments might reach $70 million, although the other three futures limit costs to below $40 million per year.

In response to stakeholder questions, Ellis said MISO would evaluate the value of avoiding emergency declarations as an additional benefit metric for a Midwest-South transmission solution, even though emergency event reduction is not a Tariff-defined benefit metric.

Design Criteria

The RTO has said proposed projects must terminate on either side of the footprint at facilities owned by MISO transmission owners. However, solutions can have midpoints outside of the MISO system, O’Brien said. Transmission solutions can either increase capacity beyond MISO’s current regional directional transfer limits or eliminate portions of the contract path.

Transmission solutions can also address other transmission constraints in addition to the North-South interface to increase the overall benefits of a project and increase the odds of approval.

“Certainly, if folks are able to provide other benefits in addition to increasing capacity between the regions, that will make a project more beneficial,” O’Brien said.

MISO North-South interface region | *MISO*

However, MISO is not yet discussing how the costs of projects might be allocated.

WPPI Energy’s Steve Leovy asked if MISO would consider a transmission solution that might be shared with the neighboring Tennessee Valley Authority.

While Ellis said MISO would not foreclose on considering such an idea, he reminded stakeholders that it’s more difficult to evaluate hypothetical agreements against a solution wholly owned by a MISO member.

“We’d have to have some sort of more assurances. What that looks like, I don’t know,” Ellis said.

Missouri Public Service Commission economist Adam McKinnie asked how MISO’s special project submission window might interact with its ongoing interregional coordinated system plan (CSP) with SPP.

“I just don’t want people to have to submit projects twice,” McKinnie said.

Ellis said any projects submitted under the CSP will be evaluated separately by the RTOs first. In the unlikely scenario that a North-South transmission project also qualifies as an interregional project, it will not be overlooked, he said.

April 29, 2019

MISO Looks to Get Better Read on Wind

By Amanda Durish Cook

CARMEL, Ind. — MISO is seeking to fine-tune its forecasting of wind generation as it faces the prospect of immense volumes of new capacity coming onto its system by 2023.

Speaking at an April 23 wind forecasting workshop, MISO forecast engineer Blagoy Borissov said the event was a “first step” in the RTO’s attempt to be transparent about its forecasting procedures and how it can improve the process.

“The timing for us is right to start having a conversation about wind forecast accuracy,” Borissov said. “In just four short years, we’re going to go from 19,000 MW to 29,000 MW of wind generation.”

He also pointed to the frequency of MISO setting new wind output records: The latest, 16.3 GW, was set on March 15.

The RTO predicts it will have more than 22 GW of wind in its system by the end of the year, rising to 29 GW by 2023. It had just 5 GW when it began its wind forecasting process in 2008.

Borissov stressed that the accuracy of MISO’s intermittent forecasts is imperative to ensuring that committed generation can meet expected load. When forecasted wind generation doesn’t materialize, the RTO must make additional commitments.

Under current practice, market participants can employ their own wind forecasts or rely on MISO. The RTO’s short-term wind forecast is updated both hourly and during every dispatch interval using five independent weather prediction models and detailed unit information that owners submit. The RTO uses the hourly forecast to satisfy must-offer requirements in the day-ahead market, while it uses the five-minute forecast for dispatch.

Where wind generators create their own forecasts, MISO incorporates that data into its models instead of filling in its own. If a resource owner fails to update its wind forecasts at least every 30 minutes, MISO reverts to using its own data in the forecast.

But MISO said it sometimes receives inaccurate forecast data from wind operators, hampering predictions of the actual generation capability of wind units.

“It definitely impacts how our wind forecasts are produced,” MISO forecasting engineer Dorsana Desai said.

Comparisons have shown that MISO’s forecasts are more accurate than those of operators, Desai said. The RTO creates standby forecasts for wind units even when they elect to furnish their own forecast data.

Market participant forecasts also suffer from a positive bias, with unit operators tending to over-forecast their generation. MISO also said it sometimes receives imprecise commercial operation dates from wind operators, compounding forecast inaccuracies.

MISO will begin performing a quarterly study to identify forecasting inaccuracies, Desai said, and email unit operators that repeatedly forecast output outside of a band of reasonableness determined by the RTO.

For its part, MISO is working to improve a time lag in its forecast algorithm, Desai said.

The forecasting workshop is in part a response to the RTO’s most recent maximum generation event, in which an inaccurate wind forecast contributed to an emergency declaration. During the Jan. 30 event, wind generation stayed well above its 2.3-GW capacity requirement that day based on Planning Resource Auction clearing. However, the RTO’s wind forecast had predicted many more wind offers into the market.

Wind output during the morning peak was about 4 GW below forecast as the worst of the cold struck the Midwest. It averaged 4.3 and 4.7 GW on Jan. 30 and 31, respectively, compared with about 13 GW for the two days prior to the event. MISO said the missed wind forecast was likely because the RTO did not factor in extreme weather cutoffs. (See MISO Details ‘Uncertainty’ Behind Winter Max Gen Event.)

“MISO has never experienced these extremely cold temperatures with the amount of wind generation we have today,” Ron Arness, the RTO’s director of central region operations, explained at a Market Subcommittee meeting in March.

In response, MISO is seeking to update the operational details of wind units by reaching out to generation owners to learn what might have changed. It will also evaluate how extreme events affects wind forecasting.

“Some of these wind units were registered eight, 10 years ago. … Maybe the information we got from the wind farms is no longer accurate,” Desai said, adding that wind operators could have since installed new technology that might affect operation of their units. She said MISO plans to reach out to all wind operators.

Beyond that, MISO is also examining using entirely new models or research to alter its wind forecasting process. Desai said such changes would represent a long-term effort, and stakeholders shouldn’t expect a major proposal any time soon.

April 29, 2019

FERC OKs NERC Violation Settlements

By Rich Heidorn Jr.

NERC reported the settlements in a spreadsheet notice of penalty on March 28.

$40,000 Penalty for Duquesne Light

Duquesne agreed to a $40,000 penalty for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6.

The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.

NERC said the violation did not indicate a systemic issue with Duquesne’s FAC-008 program because only about 3% of the company’s bulk electric system (BES) transmission facilities were affected.

The violation resulted in ratings reductions for three of Duquesne’s 85 BES transmission circuits (4%).

Although the incorrect ratings were in place for more than three years, NERC characterized the risk as minor “because the change in rating on the 138-kV circuit was minimal: just 13 amperes.”

NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.

Muni Lacked Familiarity with NERC Standards

NERC’s filing said the utility:

Mischaracterized cyber systems at a substation as low-impact BES cyber systems (LIBCS) that should have been considered medium-impact BES cyber systems (MIBCS). An incorrect analysis found the systems connected to only two other substations when they were actually connected to four other transmission assets and had ties to two different entities, NERC said.

Failed to eliminate unneeded network accessible ports from an engineering workstation in a data center.

Failed to conduct an adequate security patch management program, including a requirement to check for new security patches every 35 days. NERC cited the entity’s “lack of knowledge and understanding of CIP standards.”

Gave five employees electronic or unescorted physical access to its MIBCS without having completed access request forms.

Failed to identify in its baseline configuration all of its network accessible ports and security patches applied to assets.

Failed to perform required change management activities for BES assets, electronic access control monitoring systems and physical access control systems.

Failed to provide evidence that it removed the ability of employees to access its systems within 24 hours of a termination.

April 28, 2019

Avangrid Earnings Drop on Weak Wind

By Michael Kuser

Declining wind output drove down Avangrid’s first-quarter earnings by 11% compared to a year earlier, company officials said last week.

Avangrid posted net income of $217 million ($0.70/share), down from $244 million ($0.79/share) in the same quarter a year ago. The drop was driven primarily by a $46 million decrease in the company’s Renewables business, from $50 million in Q1 2018 to $4 million this year. Wind production during the period averaged 14% below 2018 levels, reflecting “the impacts of storms and severe weather,” CFO Doug Stuver said in an earnings call Thursday.

BOEM map shows Vineyard Wind wind energy lease area offshore Martha’s Vineyard and Nantucket. | *BOEM*

The drop in the Renewables business was partially offset by an $18 million increase in the company’s Corporate segment “due to favorable tax impacts,” Stuver said.

Total revenue for the quarter was down by 1.2%, from $1.865 billion in 2018 to $1.842 billion.

CEO James Torgerson told analysts that despite the hiccup in wind output, Avangrid expects nearly 1 GW of renewables under construction to come online this year and has increased its pipeline by 1.6 GW to 15.4 GW, which includes 4.4 GW of solar.

Its Vineyard Wind offshore project, a joint venture with Copenhagen Infrastructure Partners, is on track, “with nearly 70% of the supply chain secured,” Torgerson said. The project’s contracts with the electric distribution companies recently received Massachusetts Department of Public Utilities approval. “Now, we are targeting to have all 800 MW in operation by the end of 2021,” he said.

With their Liberty Wind project, Avangrid and Copenhagen also submitted a bid in New York’s first offshore wind solicitation, with options for 400, 800 and 1,200 MW. (See Four Bidders Vie for NY Offshore Wind Project.) The New York State Energy Research and Development Authority is expected to announce the winner this spring.

The companies also submitted to Rhode Island two proposals of 200 MW and 300 MW each, with the selection of bidders expected in May.