Page 1204 – RTO Insider

August 30, 2019

Critics: EPRI EMP Report Understates Risks

By Rich Heidorn Jr.

An electric industry-funded report on high-altitude electromagnetic pulses (HEMPs) underestimated the risks the grid faces and should not be used as the basis for mitigation, according to a critique released this week by a little-known group with ties to Maxwell Air Force Base.

In April, the Electric Power Research Institute (EPRI) released a study that concluded a HEMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. (See EMP Task Force Looks at Black Start, Nukes.)

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

A group calling itself the Electromagnetic Defense Task Force (EDTF) said almost 200 of its members — “military, government, academic and private industry experts in various areas of electromagnetic defense” — produced a critique of the EPRI report and concluded that relying on it would not address “remaining vulnerabilities impacting large power transformers, generating equipment, communication systems, data systems and microgrids designed for emergency backup power.”

“If U.S. government policymakers rely upon the methodology and conclusions of the EPRI report, effective high-altitude EMP protections will not be implemented, jeopardizing security of the U.S. electric grid and other interdependent infrastructures,” the group said in its 20-page report.

Randy Horton, EPRI’s EMP project manager and one of the authors of the April report, defended the work Wednesday. “EPRI stands behind our EMP research results and welcomes technical debates that are supported by science, facts and data,” he said in a statement. “Our conclusions were reached after three years of extensive laboratory testing and analysis of potential EMP impacts on the electric transmission system.”

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

An EPRI spokesman declined to elaborate or respond to specific criticisms, saying, “I think Randy’s quote lays out a good basis for further discussion.”

FERC declined to comment, and NERC and the Edison Electric Institute did not respond to requests for comment. Scott Backhaus, the Department of Homeland Security’s coordinator for EMP impacts on critical infrastructure, told ERO Insider on Thursday he is working on a response but that it is not complete.

EPRI’s report called for mitigation to protect the grid from the impacts of E-1 pulses — the first “hazard field” caused by an EMP, which lasts for about 2.5 nanoseconds. The second impact, an E2 EMP, lasts up to 10 milliseconds. The last hazard field, an E3, is marked by a very low frequency pulse that can last for hundreds of seconds. The event would be like a severe — albeit much shorter — geomagnetic disturbance (GMD) caused by solar flares.

EPRI acknowledged that its research was limited and did not include generation and distribution, saying it intended additional research on those subjects.

Scenario Choices

But the task force said EPRI also erred by not using realistic, worst-case scenarios in its analysis.

“Despite having access to defense-conservative Department of Defense threat scenarios, EPRI used alternative Department of Energy scenarios that assume adversaries would detonate nuclear weapons at nonoptimal altitudes, when the optimal altitudes are available in the open literature,” the report says.

The task force said a burst height of 75 km would produce the strongest E1 field strengths, but that EPRI used a height of 200 km, lowering the peak E1 field strength by almost two-thirds. Similarly, EPRI did not use the 150-km optimal burst height for peak E3 field strengths, choosing instead a height of 400 km.

The Electromagnetic Defense Task Force said EPRI did not use the 150-km optimal burst height for peak E3 EMP field strengths, choosing instead a height of 400 km. | *Electromagnetic Defense Task Force, Metatech Corp.*

“The methodology and findings of the EPRI report are not only markedly dissimilar from previous EMP studies, but in many cases entirely opposed to more than 60 years of prior DOD, government and contractor research and findings on EMP, system effects and hardening,” it said.

Russian and Chinese scientists have published research that calculated E1 impacts at least twice as great as those used in EPRI’s study, it said. “By avoiding the use of data from declassified Soviet EMP tests on the realistic E3 threat level, EPRI was able to minimize numerical estimates of damaged grid equipment, including hard-to-replace high-voltage transformers.”

“EPRI also assumed latitudes and longitudes for its detonation scenarios that are nonoptimal for producing maximum HEMP fields in the Northern Hemisphere,” EDTF said. EPRI assumed the detonation would be over the center of the U.S., not on the most populated portions of the country or the areas with most of the electric generation, the critique said.

Optimistic ‘in the Extreme’

The report says the digital protective relays (DPRs) on which EPRI focused its E1 research are more resilient than other grid elements such as substation communications and that EPRI suggested the relays would have a higher survival rate than previous peer-reviewed studies have found.

EPRI’s assessment of E1 HEMP impacts on voltage stability found that about 21,500 line terminals would be affected. Of the affected relays, EPRI assumed 1% of them would cause simultaneous tripping, which it said would cause the system to experience “perturbation” but “remain stable.”

“The EPRI report does not explain EPRI’s methodology of choosing just 1% of these relays, nor does it explain how EPRI can assume that the entire system will ‘remain stable’ when these relays are randomly tripped,” EDTF said.

Critics say a burst height of 75 km would produce the strongest E1 EMP field strengths, but that a study by EPRI used a height of 200 km, lowering the peak field strength by almost two-thirds. | *Electromagnetic Defense Task Force, Metatech Corp.*

EPRI did not assess how the failure of DPRs to prevent bus and transformer overloads or protect against over- and under-frequency and over- and under-voltage conditions would affect the grid, EDTF said.

EPRI also assumed that attackers would deploy only a single nuclear weapon in a HEMP attack, ignoring the risk of multiple HEMPS, according to EDTF.

“Protective relay damage and associated line terminal loss from realistic HEMP scenarios could be far greater, especially with a multiple-bomb EMP attack. Relay malfunction during a HEMP attack would likely cause other electric grid systems to fail, resulting in large-scale cascading blackouts and widespread equipment damage. Notably, E1 effects on protective relays are likely to interrupt substation self-protection processes needed to interrupt E3 current flow through transformers,” EDTF said.

“An initial HEMP attack could render a number of relays inoperable, causing grid debilitation due to the loss of transformer isolation, fault protection, and islanding capabilities. Thus, a follow-on HEMP attack on a grid with a portion of damaged or disrupted DPRs would likely cause increased and catastrophic equipment damage from flashovers, uninterrupted overloads, faults and cascading events resulting in a wider-scale and longer-duration blackout. Also, a second HEMP attack after damaged DPRs are replaced could eliminate the ability to recover due to depletion of DPR spare inventories.”

The EDTF noted that “large-scale grid blackouts have occurred in the past from single-point failures, such as the Northeast Blackout of 2003, which was caused by overgrown trees contacting electric transmission lines.”

The blackout affected more than 70,000 MW of load, leaving 50 million people without electricity. “In contrast, EPRI’s report concludes that a HEMP attack on the same Eastern Interconnection would cause limited regional voltage collapses and affect roughly 40% of the electrical load lost in the 2003 blackout. Experience with cascading collapse in the Eastern Interconnection shows EPRI’s finding to be optimistic in the extreme.”

Authors’ Identity Shielded

EDTF said its critique was the work of attendees of the group’s second “summit” in May under “Chatham House Rules,” in which they contributed without attribution. “The experts who contributed to this specific document range from uniformed military personnel, to civil servants throughout a range of government agencies and various national laboratories, to internationally renowned and published engineers.”

The critique was circulated by the Foundation for Resilient Societies and published on the website of Over the Horizon, which describes itself as “a digital journal that brings together disparate perspectives to advance the conversation on the emerging security environment.”

EMP — Thomas Popik, president of the Foundation for Resilient Societies | *Harvard Business School*

Resilient Societies President Thomas S. Popik, a former Air Force captain who attended the EDTF summit, said in an interview that the critique “has a firm scientific basis.”

The EDTF published the names of more than 100 organizations it said were represented at the summit, including DHS, FERC, the Joint Chiefs of Staff, NASA and several units of the Air Force. The only individual named in the critique is Air Force Maj. David Stuckenberg, who did not respond to requests for comment.

The Air Force also did not respond to questions about its relationship with the EDTF. The task force has a webpage on the Maxwell Air Force Base website, and its 2018 report is published on the website of the base’s Air University and included in the Homeland Security Digital Library. The 2018 report lists as authors Stuckenberg, former Navy Secretary and CIA Director R. James Woolsey Jr., and Air Force Col. Douglas DeMaio, who gave a presentation to the NERC EMP Task Force in July. (See Air Force: US Must Take ‘Higher Ground’ in Space.)

Popik said he wasn’t certain if Resilient Societies is part of the EDTF. “I know that we were invited to the meeting, so that would imply we’re part of the task force, but the actual conditions for membership in the task force are… I think it would be best if you ask that question of Maj. Stuckenberg.”

Incentives and Motives

EDTF said it “operates on the military’s premise of planning for the reasonable upper-bound scenarios and validating results through real-world testing.” EDTF said EPRI’s report might dissuade transmission owners and operators from mitigating EMP risks or planning for post-HEMP grid restoration. “Some EDTF personnel working on HEMP-mitigation efforts alongside electric industry partners have lost both momentum and the interest of their industry partners,” it said.

Popik praised NERC for including him as the only non-industry member of its EMP Task Force. “That’s been an open and transparent process, which is coming to a solid proposal for a process to address the executive order,” he said. “It really is very important to distinguish the work of the EMP Task Force at NERC from the efforts of the Department of Homeland Security and EPRI and [the] Department of Energy in regard to this study of EMP effects.”

He cited DHS’ Backhaus, who told the NERC task force in June that they should “use physics and engineering to constrain our analysis” and avoid overestimating the risk. “EMP is one of many threats, so we need to develop our best estimate of risk from EMPs and GMDs to place them in context of the other risks that the bulk system faces,” Backhaus said. (See EMP Task Force Takes ‘First Bite of the Elephant’.)

Popik said utilities “without a ready means for cost recovery [and] faced with the potential of a very expensive grid security standard … would have ample incentive to make sure the EMP threat was not — you can put this in quotes — ‘overestimated.’”

“… When you try and use the so-called best available science and physics and engineering to … avoid a conclusion that would be in conflict with a regulatory agenda, that’s not good science.”

August 29, 2019

ERCOT TAC Endorses Co-optimization Principles

By Tom Kleckner

ERCOT‘s Technical Advisory Committee last week endorsed three additional “foundational pieces” to real-time co-optimization (RTC), the market tool being designed to procure energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

TAC members unanimously approved the key principles in an email vote following an Aug. 28 briefing by ISO staff. The briefing was held in lieu of the committee’s regularly scheduled meeting to help the task force drafting RTC key principles stay on track.

“We want to harden [the principles] and move on. We don’t want to be like nodal and do it over again,” said ERCOT’s Matt Mereness, who chairs the Real-Time Co-Optimization Task Force (RTCTF), referencing the cumbersome effort to design and implement the grid operator’s nodal market.

“I didn’t think we needed to spend a whole meeting on this,” said TAC Chair Bob Helton, of ENGIE.

The key principles (KPs) reviewed by the TAC were:

KP 1.4 will modify the systems and applications that provide input for the current real-time market (RTM) optimization engine to accommodate the awarding of AS in real time. AS will be a resource specific award, and regulation instructions will be generation resource-specific.
KP 1.5 will modify processes for deploying AS to accommodate real-time awards. The principle will look at systems and communications between ERCOT and qualified scheduling entities in dispatching and deploying AS.
KP 3 will modify the reliability unit commitment (RUC) process to be consistent with how energy and AS will be awarded in the RTM. RUC will review resources scheduled to be available to determine whether additional resource commitments are needed to meet the load forecast and minimum AS requirements and resolve transmission congestion under defined penalty curves and factors.

The TAC held an email vote following the online session to endorse the principles. Members have until Aug. 30 to send in their votes.

The Texas Public Utility Commission directed ERCOT to add RTC to its market. The grid operator has estimated it will take four or five years and at least $40 million to modify its market, but its Independent Market Monitor says the grid operator could save as much as $400 million annually in reduced congestion costs and AS costs. (See PUCT Continues Review of Potential Market Improvements.)

The task force faces a February deadline to complete 13 key principles. It is currently working on AS demand curves and an offer structure, and it has begun discussions on changes to the day-ahead market.

The TAC in July approved the first set of five principles. (See “TAC Approves First Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: July 24, 2019.)

The task force next meets Sept. 19 and Sept. 24. The latter meeting includes a half-day lessons-learned session with MISO, PJM and SPP representatives.

August 29, 2019

EIM Governing Body Gains Member, Loses Another

By Robert Mullin

PORTLAND, Ore. — Just as the Western Energy Imbalance Market’s Governing Body was poised to fill the empty space within its ranks, another vacancy immediately popped up.

The EIM Governing Body voted Wednesday to fill the seat vacated by one of its original members — but not before revealing that its newest member had also resigned his position the night before.

Climate Change — Travis Kavulla, R Street Institute | © *RTO Insider*

Member Travis Kavulla was notably — but not surprisingly — absent from the body’s monthly meeting in downtown Portland. After all, his wife had just recently given birth, Governing Body Chair Carl Linvill told a hotel conference room packed with regional stakeholders.

But Linvill then delivered unexpected news: “We received a letter from Travis that he has been offered an opportunity which he plans to accept, which will mean that he will no longer serve — effective immediately — on the EIM Governing Body.”

Kavulla, a former member of the Montana Public Service Commission, was elected to the Governing Body in June 2018 after being term-limited out of his commission seat. (See CAISO Board Approves More CRR Auction Changes.) He currently serves as the energy director for R Street Institute, a D.C.-based think-tank that advocates for “free markets and limited, effective government.”

Kavulla, who joined R Street last October, shared his resignation letter to the EIM but told RTO Insider, “I’m not in a position to make any announcements at the moment.” The letter said he had accepted a job with a “market participant” and would be starting work next month.

Kavulla’s term as a Governing Body member was set to expire in 2021. His resignation marks the second premature departure from the body since April, when Kristine Schmidt, the group’s inaugural chair, vacated her seat to join the board of embattled PG&E Corp. Allowing Schmidt to hold both positions would have presented a conflict of interest, then-Chair Valerie Fong said at the time. (See PG&E Departure Leaves EIM Vacancy.)

To replace Schmidt, the body on Wednesday confirmed Anita Decker, a familiar name to industry participants in the Pacific Northwest.

From 2014 until earlier this year, Decker served as executive director of the Northwest Public Power Association, an advocacy group representing about 150 community-owned electric utilities in nine Western states and British Columbia. She was chief operating officer of the Bonneville Power Administration from 2007 to 2014, when she also performed a stint as acting administrator for the Western Area Power Administration. Prior to that, Decker had a 27-year career with PacifiCorp, where she rose to the position of a business unit vice president, having worked for the utility in Oregon, Wyoming and Utah.

EIM — Jennifer Gardner, Western Resource Advocates | © *RTO Insider*

“We had an incredibly qualified pool of candidates this year,” said EIM Nominating Committee Chair Jennifer Gardner, a senior attorney with Western Resource Advocates. Gardner described the deliberations leading to the nomination of Decker as being “consensus-driven,” bringing together representatives from the EIM’s various sectors in a “time-intensive process.” In addition to seeking someone with subject matter expertise, the committee put a high priority on experience in the West, with a focus on geographic diversity, she said.

“It was a difficult decision because we had some very qualified candidates, which I think speaks well to the Energy Imbalance Market in general,” member John Prescott said. “There’s a lot of interest out there from very qualified people that would like to serve on this Governing Body.”

Decker’s term will run from Sept. 1 until June 30, 2020, when Schmidt’s term was set to expire.

Not ‘Discretionary’

After the Governing Body’s three remaining members voted unanimously to confirm Decker, Fong quickly posed the question of whether the body should prompt the Nominating Committee to begin searching for Kavulla’s replacement.

“That’s technically not on the agenda,” said CAISO Senior Counsel Greg Fisher, who was sitting with the EIM leaders.

“Is it actually an action item? It’s just a recommendation that they move forward,” Fong said.

Left to right: CAISO’s Mark Rothleder and Keith Casey; EIM Governing Body members Valerie Fong, John Prescott and Carl Linvill; and CAISO’s Greg Fisher and Stacey Crowley. | © *RTO Insider*

Fisher advised against proceeding so informally, saying the matter was not “discretionary” for the Governing Body, given the amount of time left before the expiration of Kavulla’s term, which leaves uncertain the process for replacing him.

“So, we’ll wait to hear back with a formal opinion from you on that and we’ll proceed,” Linvill confirmed.

Speaking to RTO Insider about Kavulla’s resignation after the meeting, Linvill said, “We’ll miss his contributions. He was an important member of the Governing Body — and we’ll leave it to him to announce what his plans are.”

“Travis is a big loss. He brings a wealth of expertise to the Governing Body,” Gardner said. But having recently vetted the list of industry hopefuls seeking to take over for Schmidt, she was optimistic about finding yet another replacement.

“I think a lot of folks have an interest in seeing the EIM succeed. I have no doubt we’ll have an excellent pool of candidates.”

August 29, 2019January 15, 2025

MISO, PJM Eye Nov. Freeze Date Defrost

By Amanda Durish Cook

MISO and PJM said Tuesday they will propose changes to how they determine flowgate rights in a white paper in November.

The RTOs use an April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before the creation of their seam. That date is used to determine both firm flow entitlements (FFEs) used in market-to-market settlements and firm flow limits (FFLs) used in transmission loading relief (TLR).

Earlier in August, MISO staff said the RTOs were considering filing a freeze date solution that would almost certainly be opposed by nonmarket parties to the congestion management process, leaving a decision up to FERC.

During a Joint and Common Market conference call, however, the RTOs said they hope they will be able to find an agreement with the nonmarket parties — including SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. — by November. (See Outside Parties Slow MISO-PJM Freeze Date Thaw.)

PJM and MISO footprints | MISO, PJM

MISO and PJM’s proposed solution would divide flowgate rights by age, with priority to network resources from 2004 and earlier, followed by: network resources from 2004 or later; transfers between local balancing authorities to make up shortages on a pro rata basis; and RTO load served by RTO dispatch — in that order.

“Of course, the current freeze date process is not suitable for markets right now. … Of course, the solution will increase transfer rights for markets over nonmarket entities. That’s been a big concern for the nonmarket,” Andy Witmeier, of MISO’s seams administration team, said earlier in August. Witmeier said nonmarket neighbors of the RTOs are concerned that their reliability may be impacted by a decrease in non-firm transfer availability. They also fear that an increase in firm limits for post-2004 network resources could lead to more curtailments of non-firm transfers for those outside the two markets.

Witmeier had said MISO and PJM could either file the freeze date changes with changes only to the RTOs’ FFEs, leaving FFLs alone. But MISO staff said they would prefer a full solution that includes FFLs or to file a contested solution and let FERC decide.

The white paper will discuss the solution only as it applies to FFEs. Joe Rushing, of PJM’s interregional market relations team, said Tuesday that the RTOs will continue to discuss with neighboring balancing authorities how FFLs can be updated from the freeze date.

Rushing said the RTOs may consider creating a market mechanism to cut a portion of firm market flows when curtailment of nonmarket flows doesn’t provide enough relief to avoid TLRs. He also said they plan to study individual flowgates to figure out if some might be overtaxed.

He promised more discussion on the issue at the JCM meeting Nov. 19, when the RTOs expect to unveil the white paper.

No MISO Guarantee on PJM Customers’ Revenue Rights

Meanwhile, the RTOs have conceded there is no way for MISO to guarantee PJM’s customer-funded incremental auction revenue rights (IARRs) will result in a corresponding increase in FFEs.

However, the RTOs are promising more accurate estimates of increased flowgate entitlements when an IARR requires a joint coordinated study on the transmission upgrade.

Rushing said the grid operators have received little stakeholder comment on the small potential for financial risks to PJM members.

Both RTOs offer IARRs, which reflect upgrades that increase capability on their transmission facilities. IARR megawatts are awarded for the additional capability created for the life of the upgrade or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices. However, PJM’s process provides an additional option that allows a specified IARR to be awarded when a customer agrees to fund transmission upgrades necessary to support the new auction revenue rights request. PJM is also obligated to guarantee at least 80% of IARR megawatts. (See PJM, MISO Plan Study to Coordinate Incremental ARRs.)

MISO has repeatedly said it cannot make guarantees on future FFE allocations to PJM members. PJM staff have said it’s possible they won’t be able to guarantee the 80% share if transmission upgrades affect the MISO system.

August 28, 2019

PG&E Bankruptcy Split into Three Parts

By Hudson Sangree

The federal judge overseeing PG&E’s bankruptcy relinquished a major part of the case dealing with wildfire damages to another federal judge while a third part of the case is heading to state court for resolution.

U.S. Bankruptcy Judge Dennis Montali said he understood the divided process is awkward, but he wanted to speed up the case and protect the rights of fire victims.

He decided a federal district court judge, not a bankruptcy judge, should estimate the wildfire damages, which are a key component of the utility’s bankruptcy.

PG&E’s estimated wildfire damages are being litigated in federal court in San Francisco. | © *RTO Insider*

Some parties have suggested PG&E might be required to pay $10 billion to $40 billion to victims of the wildfires that scorched Northern California in the past two years.

“I felt compelled to toss the ball to the district court,” Montali told lawyers during a bankruptcy hearing Tuesday. The judge said he would be doing a disservice to victims to try to rush through the complex and unusual proceeding while attending to the rest of the massive bankruptcy case.

Phyllis J. Hamilton, chief judge for the Northern District of California, appr o ved Montali’s re q uest to assign the estimation proceeding to a trial judge. District Court Judge James Donato, whose courtroom is in the same building as Montali’s, will now hear the matter.

Montali said the state Legislature’s July passage of AB 1054 had increased the pressure to resolve PG&E’s bankruptcy more quickly. The law allows PG&E to share in a $21 billion wildfire damages fund administered by the state but only if it exits bankruptcy by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick P assage.)

“While that may seem a long way in the future, and no doubt is far too long for thousands of victims, the complexity of these Chapter 11 cases, the requirements of Chapter 11 and the need for parallel hearings and rulings by the California Public Utilities Commission — most of which pertain to regulatory matters and contractual obligations that exist apart from the wildfire claims — impose very difficult time limits on all parties, including the court,” the judge wrote.

A CPUC attorney told the judge Tuesday the commission would need time to weigh the effects of a reorganization plan on ratepayers and PG&E’s financial stability.

Earlier this month, Montali agreed to allow claims against PG&E over the October 2017 Tubbs Fire to be decided in state court.

The Tubbs Fire, which killed 22 people, destroyed more than 5,600 structures and leveled a section of Santa Rosa, Calif., was the most destructive in state history until the Camp Fire in November 2018 killed 86 people and burned 18,804 structures, destroying most of the town of Paradise.

Investigators with the California Department of Forestry and Fire Protection (Cal Fire) blamed the Camp Fire on a faulty PG&E transmission line but said the Tubbs Fire was caused by shoddy wiring on private property.

Plaintiffs’ lawyers still want a judge or jury to decide PG&E’s liability for the Tubbs Fire, however, and Montali agreed on Aug. 16 to lift a stay on legal actions against the company and allow the matter to go to state court on an expedited basis. (See Only PG&E Can File Bankrupt c y Plan, Judge Says.)

PG&E has said it plans to file a reorganization plan by Sept. 9, but that plan can’t be finalized without a better idea of the damages from the Camp Fire, the Tubbs Fire and a rash of other fires in October 2017, most of which have been blamed on PG&E equipment.

The utility has indicated it wants to establish a “capped fund” to pay wildfire victims, but Montali said he needs to know where to set the cap before approving a compensation fund.

August 28, 2019

FERC Sets Hearings in PJM Hydro Pseudo-Tie Spat

By Christen Smith

FERC ordered paper hearings Monday in disputes over the criteria PJM used to reject several hydroelectric resources from pseudo-tying into the RTO’s grid.

Both Brookfield Energy Marketing and Cube Yadkin Generation said PJM erred when it determined some of their generating resources didn’t meet the RTO’s pseudo-tie requirements, preventing the companies from offering capacity.

Brookfield Complaint

In January, Brookfield challenged PJM’s assertion its Calderwood and Cheoah generating facilities did not pass the market-to-market flowgate test or meet its extraterritorial deliverability requirements, despite maintaining a firm point-to-point service from the Tennessee Valley Authority into Duke Energy’s balancing authority area at an annual cost of $5 million. The company says it has held capacity obligations in PJM since 2014.

PJM told Brookfield in March 2018 its tests determined the facilities failed for 38 flowgates. A follow-up test three months later found the facilities failed “19 transmission elements.” PJM rejected as insufficient a report prepared by Quanta Technology that affirmed Brookfield’s point-to-point service complies with the RTO’s requirements.

PJM — Brookfield Energy Marketing’s Calderwood Dam is on the Little Tennessee River in Blount County, Tenn.

PJM’s current pseudo-tie rules were approved by the commission in November 2017. The order included a five-year transition period for resources that had an existing pseudo-tie and had cleared in a capacity auction before May 2017 (ER17-1 138). As a result of the failed tests, PJM said the Brookfield generators would be ineligible to participate in its capacity auction for the 2022/23 delivery year, after the transition period expired.

FERC ruled Aug. 26 that Brookfield’s complaint raised legitimate concerns about how PJM applied its requirements (EL19 –34). The commission noted PJM’s Tariff and Manuals do not specify the “deliverability criteria” the RTO uses for its evaluations.

“The record is not clear as to what deliverability criteria PJM uses to determine whether pseudo-tied resources can participate in the auctions, whether it uses those deliverability criteria consistently for all projects or how PJM evaluated the Brookfield facilities,” the commission said. ” … PJM has not sufficiently explained why the Brookfield facilities failed the M2M flowgate test while other external generators affecting the same flowgate (Flowgate No. 93209) did not.”

However, the commission denied Brookfield’s request to extend the five-year transition period. PJM said doing so would be inappropriate because the transition period is memorialized in the Tariff and would require a showing that the original transition was unjust and unreasonable. “Brookfield has presented neither a basis on which the commission could grant its requested interim relief nor a demonstration such relief would be appropriate in these circumstances,” FERC said.

Cube Yadkin Complaint

Cube Yadkin Generation filed its complaint after PJM informed it in June 2018 that its 220-MW Yadkin Pr o ject — the Tuckertown, High Rock, Falls and Narrows hydroelectric sites on the Yadkin River about 75 miles from Charlotte, N.C. — did not meet the “electrical distance” requirement under its pseudo-tie rules.

FERC approved the electrical distance test in its 2017 order, saying it struck an appropriate balance between allowing external resources to participate in PJM’s capacity market while providing the RTO with reliability assurance. The commission said it accepted PJM’s representation that the further its state estimator model extends beyond its own borders, the less resilient the PJM system becomes to data losses and inaccuracies.

PJM — Yadkin River hydro project | *Cube Yadkin Generation*

In its Aug. 26, order, the commission said Yadkin had raised factual questions about how PJM conducted the electrical distance test (EL19-5 1). Cube Yadkin said PJM’s identification of three electrically closest buses for the project is electrically impossible because the series arrangement of the resources — with grid connections to only High Rock and Badin — means there can only be two closest buses.

FERC said PJM did not directly dispute Cube Yadkin’s arguments but responded each site’s location has a “unique set of paths through and out of the Yadkin area to the PJM border and, given these unique paths, finding differences between each location is not unexpected.”

The commission said that raised questions as to how PJM’s algorithm selects the buses and paths used in the electrical distance test and whether the selection of the wrong bus could cause a generator to fail when it would have otherwise passed.

FERC gave PJM 30 days to respond to its questions about its methodology, with responses by Brookfield and Yadkin due within 15 days of the RTO’s filings. “After receipt of these filings, commission staff is authorized to establish additional procedures, including a staff technical conference,” FERC said.

August 28, 2019

FERC, NERC Propose New CIP Disclosure Rules

By Rich Heidorn Jr.

FERC and NERC on Tuesday asked for comment on a proposal to change how they disclose information on violations of critical infrastructure protection (CIP) rules.

FERC and NERC staffs published a white paper outlining proposed changes to their current procedures, which they said “may not be achieving an appropriate balance of security and transparency.”

From 2010 until December 2018, the public version of NERC’s CIP Notices of Penalty contained similar information as the confidential submission to FERC but excluded material NERC considered Critical Energy/Electric Infrastructure Information (CEII), such as the name of the registered entity. In 2019, NERC began submitting public line-by-line redactions of information claimed as CEII.

The commission initially treats information claimed by NERC as CEII as non-public but has reviewed those determinations — and sometimes released additional information — in response to Freedom of Information Act (FOIA) requests. The staffs said they reconsidered their approach in response to an increase in FOIA requests.

Duke Energy, which is headquartered in Charlotte, N.C., was fined $10 million for CIP violations earlier this year. | *Duke Energy*

The white paper proposes that NERC CIP NOPs include a public cover letter disclosing the name of the violator, the standards violated (but not the requirements) and the penalty amount. NERC would submit the remainder of the NOP, containing details on the violation, mitigation activity and potential vulnerabilities to cyber systems, as a non-public attachment, for which it would request CEII designation.

The only time a CIP NOP identified the violator was a 2011 case involving the Southwestern Power Administration, a federal power marketer (NP1 1 -238). “The identity of the entity in this particular case was material to the resolution of the matter, as the entity had asserted a defense regarding the extent of the commission’s authority to impose a monetary penalty on a federal entity,” the paper said.

In January, NERC recommended a $10 million CIP violation fine for a utility news organizations identified as Duke Energy. (See NERC Seeks $10M Fine for D u ke Energy Security Lapses.)

The staffs said separating public and non-public information will improve efficiency “because the information that would be made available to the public is readily identified and set forth in a cover letter. Perhaps more significantly, there is less opportunity for errors, including the inadvertent disclosure of potential CEII in the preparation and submission of CIP NOPs with line-by-line redactions.”

“The public identification of the CIP violator may result in increased hacker activity such as scanning of cyber systems and possible phishing attempts,” the staffs acknowledged. “However, the joint staffs believe that the limited information provided in the proposed cover letter would not provide an adversary with insights on the nature of the CIP violation or related cyber vulnerabilities, processes or procedures that could be used for an informed, focused attack on the violator’s cyber assets.”

The staff notice seeks comments on potential security benefits and security concerns from the new format as well as whether it will provide sufficient transparency to the public. Comments are due 30 days from the Aug. 27 notice.

FERC Commissioner Cheryl LaFleur said she was pleased the commission and NERC are reconsidering their policy, saying it was “an issue of growing controversy.” (See Reliability Conference: Deterrence or Collab o ration?)

“It is important that we handle NOPs so as to avoid subjecting the bulk electric system to risk of a cyberattack once a vulnerability is identified,” LaFleur said in a state m ent. “At the same time, I believe state regulators, members of the public, and others have a legitimate interest in such violations, and we should seek to achieve as much transparency as we can consistent with protecting legitimate security interests.”

August 28, 2019

Plan for ‘Critical’ Tx Stirs Transparency Concerns

By Christen Smith

VALLEY FORGE, Pa. — PJM stakeholders last week expressed concern that transmission owners’ proposed procedure for eliminating vulnerabilities to “critical” transmission assets could undermine FERC-ordered transparency rules.

Critical infrastructure protection standard CIP-014-2 requires physical security plans for “highly critical” transmission assets — those “that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.” Less than 20 such assets — typically substations — were identified in PJM’s footprint.

The TOs say that the physical security enhancements required by the standard will not fully mitigate the risks associated with the loss of the critical substations. Thus, they want to propose new transmission facilities to provide redundancy so that the facilities are no longer critical. The proposed Tariff Attachment M-4 outlines a process to vet proposed CIP-014 mitigation projects (CMPs).

substations are considered critical transmission assets — A PJM TO-proposed Tariff filing that skirts FERC-ordered transparency rules for replacing certain critical substations left other stakeholder sectors uneasy last week. | *Pexels*

The proposal was listed on the Markets and Reliability Committee’s Aug. 22 agenda as informational — meaning stakeholders don’t discuss it during the meeting. But it was opened for discussion at the request of the Consumer Advocates of the PJM States (CAPS) after some stakeholders wondered why the issue wasn’t vetted with involvement from all sectors.

“If the TOs aren’t taking an item like this into the Planning Committee, then what is the point of the PC?” CAPS Executive Director Greg Poulos asked, referring to the path stakeholders usually take to endorse Tariff filings. “It’s certainly something we need to discuss.”

According to PJM rules, replacing these CIP-014-2 assets — which count as a subset of supplemental projects — with new facilities must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed.

TOs suggest a vetting process in which PJM would confirm that the CMPs do not overlap with an existing baseline upgrade in the Regional Transmission Expansion Plan or harm system reliability. TOs would also consult state commissions, but public review of the project wouldn’t begin until after it is put into service. The TO zone where the project was built would assume 100% of the cost, according to the draft, keeping in line with other supplemental project rules. The filing would sunset after five years.

critical transmission assets — Ken Seiler, PJM | © *ERO Insider*

“There is a finite number of these facilities,” said Ken Seiler, PJM’s vice president of planning. “Our goal is to get those facilities off the list, so they are no longer critical. Our goal is to get it to zero and have no further facilities like this in our future going forward.”

Pulin Shah, director of transmission strategy and contracts for Exelon, told the MRC it was accepting stakeholder comments on the Tariff filing via email through Sept. 16.

“We do not have a particular time frame [for filing] because this is essentially a TO initiative,” he said. “The feedback process can impact next steps. If we receive no comment, we move to the next step in preparing a filing. If comments require an extensive level of responses, obviously that’s going to affect next steps.”

Many in the room, however, objected to the process through which the language was drafted and wondered how the sector would provide transparency into the concerns raised through the emailed comments.

“It could be viewed as a stepping stone to putting more supplemental projects behind a veil where there is no transparency to customers,” said Susan Bruce, an attorney representing the PJM Industrial Customers Coalition. “I think you can presume that you will get questions. My hope is that there is a process around [those questions] that is transparent to those of us who asked them.”

David “Scarp” Scarpignato of Calpine questioned the cost of replacing the facilities.

“How many dollars are you talking about here? That’s a pretty serious consideration,” he said. “If you are talking about super critical things … I’m thinking it’s in the lots of billions. Why is this not open to competition?”

Steve Herling, PJM’s executive consultant, said cost assumptions can’t be made at this stage, given that the proposed process is not yet in use and no solutions have been offered.

August 26, 2019

NEPOOL Reliability Committee Briefs: Aug. 20, 2019

The New England Power Pool Reliability Committee last week indicated its displeasure with the re –evaluation of the fuel-security reliability review for Mystic Units 8 and 9, rejecting a motion that the review had been performed in accordance with ISO-NE’s market rules and planning procedures.

The motion, which required a two-thirds vote to pass, failed with only 26.65% in favor, with overwhelming opposition from the Generation, Transmission and Alternative Resources sectors. The Supplier and Publicly Owned Entity sectors were split, and the End User sector lacked a quorum.

ISO-NE sought to retain Mystic 8 and 9 for Forward Capacity Auction 13 after Exelon said in March that it would retire the entire 2,274-MW facility, including Mystic 7 and Mystic Jet, when its capacity supply obligations expire on May 31, 2022. FERC Approves Mystic Cost-of-Service Agreement.)

NEPOOL — Interconnected system representation for 2023 (MW) used for a discussion of proposed tie benefits and ICRs with and without Mystic Units 8 and 9 | *ISO-NE*

For the re-evaluation for FCA 14, the RTO’s analysis looked at 18 scenarios and included increases in the amount of natural gas and fuel oil modeled and increases in the capacity values of some renewable resources.

The new analysis concluded that Mystic should continue to be retained because its retirement would violate two triggers: the use of load shedding in any hour under Operating Procedure 7 and the depletion of 10-minute reserves below 700 MW in an hour in the absence of a contingency in more than one LNG supply scenario.

[Editor’s Note: Speakers who raised objections to the analysis declined to be quoted on the nature of their concerns.]

The RTO’s assistant general counsel for markets, Christopher Hamlen, said the analysis was well vetted by the RC over the last year, so the methodology employed for the re-evaluation should have come as no surprise.

Norm Sproehnle, the RTO’s manager for outage coordination, said four generators that submitted retirement delist bid requests for FCA 14 — Yarmouth 1 (summer capacity of 50 MW), Yarmouth 2 (48 MW), Ipswich Diesels (9.3 MW) and Pinetree Power (16.9 MW) — did not need to be retained for fuel security.

Transmission operability analyses also found the resources could retire because none resulted in voltage or thermal criteria violations, said Abimael Santana, senior engineer in system planning.

The RC voted unanimously that the analyses for the four resources were in accordance with the market rules and planning procedures.

ICAP Requirements and Tie Benefits

The RTO’s manager of resource studies and assessments, Peter Wong, presented a review of the installed capacity requirements (ICR) and tie benefits for capacity commitment period 2023/24 (FCA 14), with and without Mystic 8 and 9.

For FCA 14, including or excluding the units in the New England resource mix will change the total tie benefits to New England by 30 MW, he said.

FCA 14 tie benefits assumptions for the calculation of the ICR-Related Values will be 1,940 MW for the scenario including the units, and 1,910 MW for the scenario excluding them.

Hydro-Québec interconnection capability credits for FCA 14 for the “including Mystic” scenario will be 941 MW, while for the “excluding” scenario will be 943 MW, he said.

Assuming RC approval Sept. 25 and Participants Committee approval Oct. 4, the RTO plans to file with FERC by Nov. 5 ICR-related values for FCA 14, both including and excluding Mystic 8 and 9, Wong said.

The RTO will be sharing additional results with the NEPOOL Power Supply Planning Committee on Thursday.

FCM Planning Procedures

ISO-NE Director of Transmission Strategy and Services Al McBride revisited the topic of moving recently developed changes to Planning Procedure 10 (PP10) to the Tariff to support the Forward Capacity Market, as discussed at the combined RC and Transmission Committee meeting in July. (See “Modifying Interconnection Procedures,” NEPOOL RC/TC Briefs: July 16-17, 2019.)

McBride said the RTO is proposing to create a new section in the Open Access Transmission Tariff for the PP10 provisions. Changes include methodologies to update the levels of interconnection service for generators after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the FCM.

If approved by NEPOOL committees in September and October, and by the PC on Nov. 1, the changes would take effect in January 2020, he said.

The PP10 revisions will become effective after the proposed Tariff revisions are accepted by FERC and become effective, McBride said.

Revising Operating Procedure 14E

The RC voted to recommend that the PC support revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.

Jerry Elliott, a principal analyst in system operations at ISO-NE, presented the proposed revisions, which the PC will vote on at its Sept. 13 meeting.

Elliott also presented proposed revisions to OP-19, for a future vote. They would add the use of phase shifting transformers and adjustments of reactive flow to normal system actions performed by the RTO and each local control center to ensure transmission reliability.

In addition, he notified the RC of changes to OP-19 Appendix K to reconcile National Grid and NSTAR operating voltage limits with Master/Local Control Center Procedure 15 Attachment H – Voltage System Operating Limit Identification Procedure.

ISO-NE Lead Operations Analyst Kory Haag presented proposed revisions to OP-23 Appendix H, for a vote in September. They would clarify the data that are required for reactive capability test requests. The proposed effective date is in October 2019.

Maine Dominates PPAs

The RC approved several proposed plan application (PPA) notifications for solar and wind generation, as well as related transmission upgrades, most of them in Maine.

The committee voted to recommend to ISO-NE that the following projects will not have a significant adverse effect on the stability, reliability or operating characteristics of the transmission facilities of the applicant, the transmission facilities of another transmission owner or the system of a market participant:

Central Maine Power to install the 7.2-MW BD Solar Augusta solar array in Augusta, Maine, and interconnect it to the Blair Road Substation, with a proposed in-service date of Sept. 1, 2020.
CMP to install the 9.2-MW BD Solar Oxford solar array in Norway, Maine, and interconnect it to the Oxford Substation, with a proposed in-service date of Sept. 1, 2020.
NextEra Energy Resources to install the 75-MW Dawn Land Solar project in Washington County, Maine, as well as a transmission application to install a station transformer at the Deblois Substation to interconnect the solar array. Proposed in-service date is May 31, 2022.
Emera Maine to construct a new 115-kV substation and expand the Deblois Substation, adding one 115-kV breaker at the new substation and four 115-kV breakers at Deblois; adding 13.4 miles of 115-kV transmission line from the new substation to the Deblois substation; a new transformer and three new breakers at the new substation; and other associated transmission work. The proposed in-service date is May 31, 2022.
Con Edison Energy to replace the existing automatic voltage regulation on the Schiller CT 1 with a Basler DECS-250 digital pilot exciter. Proposed in-service date is in September 2019.
NextEra to install the 20-MW Randolph Center solar array in Randolph, Vt., and interconnect it to the Randolph Center 46-kV substation, with a proposed in-service date of Nov. 1, 2021.
SWEB Development to install the 20-MW Silver Maple wind farm in Penobscot County, Maine, and interconnect it to the Randolph Center 46-kV substation and to the Silver Maple four-breaker ring bus substation, with a proposed in-service date of Dec. 16, 2020.
Emera Maine to install a four-breaker ring bus substation in Penobscot County for the Silver Maple project, with a proposed in-service date of Oct. 1, 2020.
NextEra to install the 50-MW Chariot Solar facility in Hinsdale, N.H., and interconnect it to the 115-kV line between the Vernon Road Tap and Vernon Road Substation. The proposed in-service date is Nov. 1, 2023.
NextEra to build a new 115-kV three-breaker ring bus substation in Hinsdale to interconnect the solar project (proposed in-service date Oct. 1, 2021), as well as to install a station transformer that interconnects to the new substation, with a proposed in-service date of Sept. 27, 2023.

Competitive Tx RFP

ISO-NE Transmission Planning Director Brent Oberlin led the fourth discussion at the RC of competitive transmission solicitation enhancements. The package of changes being presented at the RC and TC includes proposed clarifications to Attachment K of section II of the Tariff, the draft Selected Qualified Transmission Project Sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.

The focus of the discussion with the RC was on the changes to the Tariff in section III.12.6 and the definitions in section I.2.2. Oberlin said that no comments had been received since the RC meeting in July, so the language remains unchanged from what had been presented previously.

Oberlin also said ISO-NE is still looking to act on the issue at the RC meeting in September.

Based on the results of the 2028 Boston Needs Assessment, the RTO plans to issue its first solicitation for a competitively developed transmission solution in December 2019.

Tx Cost Allocation

The RC voted unanimously to recommend that ISO-NE approve pool-supported costs estimated at $28.1 million for New England Power to replace 345-kV structures on the 303 and 3520 lines in Massachusetts.

NEP will replace 126 of 142 structures on the 303 line from Berry Street Substation to the ANP Bellingham Station and on the 3520 line from ANP Bellingham Station to the West Medway Substation because of asset conditions and installation of optical ground wire (OPGW) on both lines.

The committee accepted that none of the costs associated with the upgrade are considered localized costs.

Capacity Cost Compensation

The RC voted unanimously to recommend that ISO-NE approve two dynamic reactive resources as meeting the capacity cost compensation program (CCCP) eligibility requirements defined in the Tariff.

The resources, Canal 3 (Asset ID No. 38310) and Lisbon Resource Recovery (Asset ID No. 462), were recommended to have their qualified resource recovery designation to be effective Sept. 1.

Consent Agenda

The RC did not vote on its consent agenda that included one level 1 and 50 level 0 PPA notifications for solar generation, with 25% of the projects paired with battery storage.

One stakeholder noted the large number of hybrid solar/storage projects and wondered if ISO-NE was keeping tabs on the amount of energy storage being paired with solar each month.

McBride said the RTO has not been keeping that statistic separately but would consider the request. RC Chair Mariah Winkler said it appeared to be an issue of categorization.

Winkler said that the RTO would bring a revised consent agenda to the RC next month.

— Michael Kuser

August 26, 2019

PJM TO Tariff Filing Stirs up Transparency Concerns

By Christen Smith

VALLEY FORGE, Pa. — PJM stakeholders last week expressed concern that a proposed Tariff filing by transmission owners could undermine FERC-ordered transparency rules for certain supplemental projects.

Consumer Advocates of the PJM States (CAPS) asked the Markets and Reliability Committee last week to open up discussion on the agenda item that was originally listed as informational — meaning stakeholders don’t discuss it during the meeting — after some wondered why a Tariff attachment that dealt with “critical” transmission assets wasn’t vetted with involvement from all sectors.

PJM — A TO-proposed Tariff filing that skirts FERC-ordered transparency rules for replacing certain critical substations left other stakeholder sectors uneasy last week. | *Pexels*

“If the TO’s aren’t taking an item like this into the Planning Committee, then what is the point of the PC?” CAPS Executive Director Greg Poulos asked, referring to the path stakeholders usually take to endorse Tariff filings. “It’s certainly something we need to discuss.”

The attachment in question, developed by multiple TOs, outlines a process to vet transmission system enhancements designed solely to remove critical assets — typically substations — from the CIP-014-2 list, which contains fewer than 20 assets within the PJM footprint. NERC reliability standards deem these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”

TOs suggest a comprehensive vetting process that involves analysis and confirmation from PJM that projects capable of removing the assets from the CIP-014-2 list do not overlap with an existing baseline upgrade in the Regional Transmission Expansion Plan nor do they harm system reliability. TOs will also consult state commissions, but public review of the project won’t begin until after its put into service. The TO zone where the project was built will assume 100% of the cost, according to the draft, keeping in line with other supplemental project rules. The filing will sunset after five years.

“There is a finite number of these facilities,” said Ken Seiler, PJM’s vice president of planning. “Our goal is to get those facilities off the list so they are no longer critical. Our goal is to get it to zero and have no further facilities like this in our future going forward.”

Pulin Shah, director of transmission strategy and contracts for Exelon, told the MRC it was accepting stakeholder comments on the Tariff filing via email through Sept. 16.

Susan Bruce, PJM Industrial Customer Coalition | © *RTO Insider*

Many in the room, however, objected to the process through which the language was drafted and wondered how the sector would provide transparency into the concerns raised through the emailed comments.

PJM — David “Scarp” Scarpignato, Calpine | © *RTO Insider*

David “Scarp” Scarpignato of Calpine questioned the cost of replacing the facilities.

Steve Herling, PJM’s executive consultant, said cost assumptions can’t be made at this stage, given that the proposed process is not yet in use and no solutions have been offered.