CARMEL, Ind. — A key annual capacity report issued by MISO and the Organization of MISO States predicts the RTO is now unlikely to face a near-term shortfall in generation — a welcome reversal of last year’s more worrisome findings.
Credit the change to expectations for flat demand and the promise of ample resource additions.
The survey released Friday forecasts a generation surplus of about 3 to 6 GW in 2020, though the RTO says “continued action will be needed to ensure sufficient resources are available going forward.” Last year’s survey forecasted a possible 0.1-GW shortfall in 2020.
2019 OMS-MISO survey results | MISO
Unsurprisingly, OMS and MISO say the future through 2024 could bring a “range” of resource amounts, but the survey no longer predicts any regional shortfalls in generation before 2022.
Using this year’s 16.8% planning reserve margin as a baseline, the survey predicts a 1- to 4-GW surplus in 2021. By 2022, that excess dwindles to 1 to 3.4 GW. The range of possibilities in 2023 and 2024 varies the most, with the forecast indicating anything from a 1.3-GW shortfall to a 7-GW surplus in 2023, and a 2.3-GW shortfall to another 7-GW surplus in 2024.
MISO said more than 97% of its load-serving entities and additional non-LSE market participants responded to the survey.
Last year’s survey showed MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall from 2020 to 2023 and predicted spare capacity ranging from 0.6 to 6.6 GW this year. (See OMS-MISO Survey Reveals Dimmer View of Future Supply.) The newest survey results are also a far cry from the 2016 iteration, where MISO said a generation shortfall was possible in 2018.
But during a call Friday to discuss the results, MISO staff cautioned that the 2019 survey results will differ from future realities. MISO Executive Director of Resource Planning Patrick Brown stressed that capacity deficiencies could occur “if no action is taken.”
MISO said certain Midwestern zones could develop the greatest resource adequacy risks, including Southern Illinois’ Zone 4, Indiana and western Kentucky’s Zone 6, and Lower Michigan’s Zone 7. MISO said it foresees “lower resource commitments” in those areas in 2020 and beyond, including a possible 0.2- to 0.7-GW deficit in downstate Illinois and a potential 0.9-GW shortage in Lower Michigan in 2020.
But a possible capacity shortfall isn’t an immediate concern even in those areas, Brown said.
“Zones with deficiencies don’t automatically have a resource adequacy risk as they can use surplus resources outside of their zone … taking advantage of MISO’s footprint diversity. … They do have the option to import capacity into their zones to meet their local needs,” Brown said.
Brown also said those areas have ample time to adjust to ensure appropriate capacity. Contrary to OMS-MISO results, the Michigan Public Service Commission has said that state will have sufficient capacity in place to meet obligations through 2022, he noted.
As with prior reports, MISO’s demand growth rate is set to decline again, with the five-year annual rate adjusted to 0.2%, down from a 0.3% projection in 2018.
“Fewer resources are needed to serve load,” Brown said.
MISO has only expected “modest” changes in peak load over the next five years, anticipating a 4.4-GW variance in expected system peak, with electric vehicles adding about 1 GW in demand by 2023. The RTO doesn’t expect its current approximate 120-GW peak predictions to be “radically different” within five years, market design team member Dustin Grethen said at a June 6 Market Subcommittee meeting.
As of May, MISO’s generator interconnection queue consisted of 640 projects totaling 100.7 GW, nearly 30 GW of which (210 projects) are solar generation.
Brown also said this year’s survey shows significant amounts of generation retirements, with “a mix of wind, solar storage and gas” as well as load-modifying resources lined up in the interconnection queue set to replace them. MISO does expect emergency declarations to become more frequent as a result, he said.
The RTO plans to post and discuss the survey results in more detail, including a zonal breakdown, at its July Resource Adequacy Subcommittee meeting.
WASHINGTON — Several members of the House Energy and Commerce Committee’s Subcommittee on Energy on Wednesday urged FERC commissioners to holistically review RTO and ISO governance rules, while also pressing them on when to expect decisions on languishing dockets — including PJM’s capacity market proposal.
The commissioners did not tell the subcommittee anything they haven’t said before in open commission meetings or keynote industry speeches. And because the dockets are still pending before them, they could neither go into specifics nor estimate when any decisions would be forthcoming.
But House members gave RTO issues considerable airplay in an oversight hearing that ran the gamut: the commission’s role, if any, in mitigating climate change; landowner complaints over natural gas pipeline siting; and energy storage participation in wholesale electricity markets, to name a few.
Rep. Michael F. Doyle (D-Pa.) scolded FERC for creating uncertainty in PJM, where the Board of Managers decided to move ahead with the RTO’s annual Base Residual Auction this year (albeit in August, instead of May) despite the commission finding its capacity market rules unjust and unreasonable — running the risk that FERC could force it to rerun the entire thing later. (See PJM to Hold Capacity Auction in August.)
Doyle noted PJM filed its revised rules in October, “so either a rule is going to be published right before August, which won’t give participants enough time to adjust, or a decision will not be published, and participants will have to take part in an auction under rules that FERC has found to be unjust and unreasonable.”
Chairman Neil Chatterjee assured Doyle that “we’re working as diligently as we can.”
“This is a vexing challenge,” Chatterjee said, “because you have a situation where two things I think we all believe in — states’ rights and the markets — are colliding. … We’re coming to a point where actions that states are taking to make decisions about their local energy futures are impacting the markets and trying to figure out how to sort through that while ensuring just and reasonable rates has proven to be very, very challenging.”
“I am deeply, deeply troubled by the delay,” Commissioner Cheryl LaFleur said. “I had dissented in the initial order because I thought it would put PJM in an impossible situation, and I’m afraid that’s exactly what’s come to pass. I’ve been using my world-class powers of nagging to be a nag about it, but so far we have not gotten an order out.”
“I’m not sure how the auction can go forward without some clarity from FERC,” Commissioner Richard Glick said.
Speaking to reporters after the hearing, Glick said, “We should be working on this 24/7 because we owe it to [PJM] to provide some more certainty.”
Rep. Frank Pallone (D-N.J.), chair of the full committee, called for “greater scrutiny of wholesale capacity markets. Frankly, the current state of affairs is a mess, especially in the PJM market, where New Jersey participates. PJM participants are currently left in the lurch of both an old and new capacity market design. … It is vital that we figure this out immediately.”
Subcommittee Chair Bobby Rush (D-Ill.) expressed concern that “consumer voices are often overlooked, ignored or cut out of the RTO process entirely.” Pallone also noted “there has not been a comprehensive review by FERC of each RTO’s stakeholder process to ensure compliance with the requirements of Order 719,” issued in 2008.
“This is something we continually hear from people around the country,” Chatterjee replied. Reviewing Order 719 compliance “is one option, but looking with an eye towards ensuring consumers’ voices are heard as they come up through the process is another manner in which to do this. I think particularly as new technologies come into play and we look to break down barriers to entry, we need to ensure these new voices have an opportunity to be heard at the RTOs and ISOs.”
LaFleur agreed that “it’s probably a good time for a relook.”
Call for Transparency
Rep. Joe Kennedy III (D-Mass.) said he was “increasingly concerned about the [RTOs] and their governing structures.”
“My fellow citizens and I have no idea who makes decisions or how they are made at [the New England Power Pool] because unless you are a member, you can’t even observe any meetings or proceedings, let alone talk about it publicly. Other RTOs benefit from governance structures that enjoy slightly more transparency. Still, I believe more has to be done.” He asked LaFleur if the public should have more access, “even as a passive observer.”
LaFleur noted a pending request for rehearing on press access to RTO meetings before she began to point to consumer advocates’ participation in RTOs. Kennedy interrupted her, but LaFleur said she could not comment on the press issue.
FERC in April dismissed RTO Insider’s complaint seeking rejection of rules proposed by NEPOOL to keep reporters from publishing what is discussed at the group’s meetings. Consumer advocacy group Public Citizen filed a request for rehearing last month (EL18-196). FERC issued a tolling order June 7, giving itself more time to consider the request. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)
Glick jumped in. He also said he could not comment specifically on the rehearing request, but he explained that FERC rejected the complaint because it lacked jurisdiction, as press access does not affect NEPOOL’s wholesale rates. But he said, “I agree with you, congressman, that transparency is a very important element of appropriate RTO functioning.”
A recent pair of dueling studies have drawn divergent conclusions about the merits of competitive transmission solicitations. The differences might have something to do with the reports’ respective sponsors.
Both studies appear to be aimed at shaping the discussion around possible changes to FERC’s Order 1000, the 2011 rulemaking that eliminated incumbent transmission owners’ right of first refusal over regional projects and opened transmission planning processes to independent developers.
The first report, released by The Brattle Group in April, found electricity customers could save $8 billion over five years if competitive transmission planning processes expanded to cover 33% of all transmission investments, compared with just 3% today. That study was commissioned by independent transmission developer LSP Transmission Holdings, whose affiliates are developing three competitively bid transmission projects in MISO, PJM and NYISO.
But another study published by Concentric Energy Advisors on Monday concludes there is no basis to expand the scope of competitive solicitations in RTOs and ISOs, claiming incumbent TOs’ initial cost estimates for projects generally prove to be accurate. That study was prepared for Ameren, Eversource Energy, ITC Holdings, National Grid USA and Public Service Electric and Gas — all incumbent TOs in various RTOs.
The two studies come as FERC is signaling a move to reexamine Order 1000. FERC Chair Neil Chatterjee earlier this year acknowledged some industry stakeholders are complaining the rules are not working as intended, with proponents of competitive projects seeking a replacement and opponents hoping for a repeal. (See “Chatterjee: Focused on PURPA, Order 1000 Reforms,” Overheard at the NARUC Winter Policy Summit.)
So far, the commission appears to be in the “replace” camp.
“As we think about addressing Order 1000, I believe we owe it to consumers to put our best effort forward toward spurring competition to work and getting the scope of competition right,” Chatterjee told a gathering of state regulators in February.
Order 1000 Rethink?
But the numbers suggest competitive project developers continue to face barriers despite the aims of Order 1000.
Brattle’s report showed that even seven years after FERC issued the order, 97% of RTO transmission investments are still made outside competitive processes. The study calculated that competitively bid projects only took about $540 million of the average $20 billion in annual transmission investment from 2013 to 2017, despite its finding that competitive projects typically result in cost savings of 20 to 30%.
Brattle took issue with the ongoing limitations faced by competitive developers.
“The tariffs that specify the rules for transmission planning for each region currently exclude the large majority of transmission investments from competitive processes,” Brattle wrote. “We do not see compelling policy reasons for broad limits or having significant differences in criteria used in various regions that directly or indirectly exclude transmission projects from the competitive processes.”
The report advocated federal and state policymakers move to expand the scope of competitive transmission investments to stimulate innovation and increase cost-effectiveness in an industry being transformed by new natural gas and renewable generation investments.
But Concentric contends Brattle’s report doesn’t paint a complete picture, maintaining the benefits of transmission solicitations are still unknown and Brattle’s cost-savings estimates are flawed. Concentric also argues RTO competitive processes are “time- and resource-intensive,” with solicitations involving more than one bidder taking anywhere from 113 to 1,498 days.
Concentric also questioned Brattle’s assumption that incumbent TO projects typically exceed initial cost estimates by anywhere from 18 to 70%, calling that conclusion “false and inconsistent with the empirical evidence.”
Instead, Concentric said it found incumbent TOs’ final project costs only vary from initial investments by a “very modest” -2.9 to 7%.
Concentric said there’s “no credible support for the claim that current transmission processes limit customer savings, or that expansion of competition will yield meaningful additional savings.”
“The Brattle report … uses a limited and unrepresentative sample size of incumbent TO projects to produce its average historical cost escalation estimates, which are significantly overstated,” Concentric added. “Importantly, of the 15 [competitive] projects the Brattle report used to calculate its cost savings estimates, the final cost of the majority of the projects is currently unknown.”
Concentric cautioned against any near-term moves to revise or replace Order 1000.
“If there is interest in expanding solicitations for transmission projects, we advise policymakers to wait until more of the projects selected through such solicitations have been placed in service. At such a time, more information will be available about the actual costs and operational performance of these projects and policymakers would be in a position to make better informed decisions about whether or not to expand such solicitations,” Concentric said.
Jim Holodak, National Grid vice president of FERC and wholesale regulatory strategy, agrees with that last point. He said he’s heard a variety of opinions about revisiting Order 1000, ranging from elimination or repeal to a series of slow modifications.
“We’re suggesting we need more time before FERC opens it up,” Holodak told RTO Insider.
He said multiple competitive projects should be completed before cost savings and benefit assumptions are made about them.
“You don’t know what that project will cost until it finally goes into service. Then make that comparison,” Holodak urged.
Concentric’s study pointed out that even the cost caps promised by winning bidders for competitive projects are subject to “exclusions and exceptions.” Holodak noted the caps can contain several exclusions related to siting, regulatory requirements and routing changes.
“There’s a whole host of exclusions for cost caps. … At the end of the day, they’re not taking on any more risk, and the project price for customers is not really capped” any more than for an incumbent TO project, Holodak said.
“It’s as if you’re buying a kitchen remodel based on an ad for a $10,000 kitchen, but you want to add granite countertops and other design features that increase the quote. It would be unreasonable to expect to hold the contractor to the original ad price,” he said.
Holodak also argued the system’s “resiliency and robustness” won’t get the same attention if more project types are opened to competition. Complete competition on every level of transmission “is not the way to go,” he said.
Brattle Responds
Brattle’s conclusions couldn’t differ more.
Johannes Pfeifenberger, one of the authors of the Brattle study, said he still stands by the position that Order 1000 is ready for expansion, even if there are few case studies so far.
“The reality is there are not a lot of competitive projects to study. But the experience with those 15 Order 1000 projects is that those projects were bid below initial cost estimates,” Pfeifenberger said.
While Brattle is only beginning its review of the Concentric report, Pfeifenberger leveled several criticisms at Concentric’s study methodology, saying the competing analysis incorrectly relied on updated cost estimates later filed by the incumbent transmission developers, not true initial cost estimates.
“Since the competitive bids are compared against the initial estimates when the bids come in, the initial estimates are the most appropriate information for comparison,” Pfeifenberger explained.
Pfeifenberger also said the average 20 to 30% cost savings found in the Brattle study is consistent with the savings seen in other areas with transmission competition, including the U.K.; Brazil; Alberta, Canada; and the Path 15 transmission project in California.
He also lightheartedly addressed the cost cap criticisms: “I would say that some cost caps are better than no cost caps.”
Pfeifenberger also pointed out all transmission projects must undergo a process of identification and then study before approval. He said the planning process takes time, with or without bid windows and selection reports.
“The competitive process had only begun a few years ago, and these markets are still in the forming stage, and therefore the first few competitive projects take quite a bit of time to evaluate and approve. But these processes are improving and streamlining over time,” Pfeifenberger said.
“If you can add six months [to the planning process] and save 20%, was that worth it?” he asked rhetorically.
But Holodak maintains early planning estimates at the conceptual design stage shouldn’t serve as a study benchmark for cost savings, noting they often involve standard dollar-per-mile estimates and lack several design and engineering details unique to specific transmission projects.
“Nobody has ever suggested that’s a model you should hold someone to. Brattle’s suggestion that the preliminary planning estimate is a standard someone should be held to, we think it’s completely without merit,” Holodak said.
Brattle report co-author Judy Chang argued planning-level estimates could become more precise.
“It doesn’t make sense that project costs will always escalate based on the initial estimates,” Chang said. “That also means that nobody really cares about the initial estimate. The whole competitive process has induced these transmission owners to sharpen their pencils and really analyze costs they can control and bear the risk of costs coming in higher than they expect. This whole better cost containment is an innovative outcome of the competitive process. This is a benefit.”
Pfeifenberger added if planning-level estimates are made to be exceeded, then competitively bid projects would also consistently exceed those estimates. That’s not the case, he said.
“Beyond trying to confuse the issue, Concentric has not addressed the fact that competitive bids have come in significantly below initial cost estimates while traditionally developed projects of similar type have come in above their initial cost estimates,” he said.
VALLEY FORGE, Pa. — PJM’s Darlene Phillips will take over the Operating Committee in July after current Chairman Dave Souder starts his new role as executive director of systems operations.
Phillips is currently the senior director of strategic policy and external affairs and joined PJM in August 2015. She served in several leadership roles for MISO for more than 10 years and is a graduate of the University of Michigan and Indiana University’s Robert H. McKinney School of Law.
Souder’s promotion comes after a leadership shake-up following CEO Andy Ott’s retirement, effective June 30. (See PJM CEO Ott to Retire.) He will take over the role for Ken Seiler, who will become vice president of planning and be responsible for the oversight of the System Planning Division, which includes transmission planning, interregional planning, interconnection analysis, interconnection projects, infrastructure coordination and resource adequacy planning.
PJM said a wave of tornadoes on Memorial Day and throughout the last week of May left about 80,000 customers without power around Dayton, Ohio.
Half the customers were restored within 12 hours, staff said, but several transmission lines remain inoperable due to storm damage. PJM expects the lines will be under repair through the end of June.
Energy Storage Revisions Get First Read
Revisions to PJM manuals for energy storage mandates got a first read during Tuesday’s OC meeting. PJM staff said the changes follow directives from FERC Order 841.
First up were changes to Manual 14D: Generator Operational Requirements, including Operating Agreement definitions of energy resource, capacity resource, energy storage resource (ESR) and capacity storage resource. Language was also added to clarify applicability of manual requirements to generation and storage resources. Sections 4.1.7 and 4.2.3 were revised to include telemetry of state of charge for ESR model participants and specific metering requirements. Staff also added a definition for generating facility per FERC’s compliance filing for Order 845.
In Manual 36: System Restoration, PJM revised the exception to critical cranking power to include non-hydro energy storage resources and updated the participation model to allow ESRs to participate in all markets where technically feasible.
In Manual 40: Training and Certification Requirements, sections 3.2.4 and 3.2.6 were updated to account for small generation resource dispatchers and lower the megawatt threshold for training requirements to accommodate ESRs. Language was also changed to reflect ESRs are assumed to be more than participants in ancillary markets.
Laura Walter, a senior lead economist for PJM, said the purpose of the revisions — and many more anticipated in other manuals — is to open up markets for ESRs and ensure parameters allow such resources to operate effectively.
PJM’s ESRs include approximately 5,000 MW of pumped hydro and 310 MW of battery storage, she said. The resources will be allowed to offer into both the day-ahead and real-time markets and will be modeled as continuous resources with the ability to self-manage their own state of charge.
The manual revisions will return to the September OC for final endorsement to give stakeholders time to provide additional feedback.
Nuclear Plant Interface Coordination Updates
PJM wants to update Manual 39 with new sections and clarifying language for its nuclear plant interface coordination procedures.
The revisions include new language in sections 2.7, 3.6 and 3.7 that address coordination around remedial action schemes and load shedding schemes. They also cover the deactivation and retirement process for nuclear units and the regulatory requirements of that process, as well as the coordination between reliability coordinators when a non-PJM member is identified by a nuclear plant generator operator as a transmission entity.
Attachment B will also be renamed to “Plant Specific NPIRs.” Endorsement is scheduled for the July OC.
Emergency Operations Updates
Staff added multiple section changes to Manual 13: Emergency Operations to align with the new Markets Gateway functionality for resource limitation reporting to be implemented on Aug. 1.
Sections 1.1, 2.3, 3.1-3.5 and 5.2 have been revised to reflect the following:
Terminology for “fuel-limited” units has changed to “resource-limited” to clarify applicability of reporting requirements.
Units are considered resource-limited if they have less than 72 hours of remaining runtime at maximum capacity, limited by primary/alternate on-site fuel, emissions, demineralized or cooling water or other consumables.
Resource-limited units are to report resource limitations via the new Markets Gateway page.
Natural gas-fired units with fuel limitations are not considered resource-limited and are excluded from resource limitation reporting via the Markets Gateway.
References to the Supplementary Status Report (SSR) for reporting resource limitations have been removed and replaced with instructions for using the new Markets Gateway page.
In Section 6.4, clarifications were made to address procedures when PJM has declared conservative operations or hot/cold weather alerts:
Fuel-limited gas-fired units are not to be placed in maximum emergency but should remain available to ensure PJM tools “economically schedule” the gas-fired units, unless PJM Dispatch directs them to be placed in maximum emergency dispatch status.
Dual fuel units — gas/other on-site fuel — should be placed in maximum emergency status when non-fuel resource limitations restrict runtime to less than 16 hours for combustion turbines and 32 hours for steam turbines. When fuel is limited, they should be placed in maximum emergency status only when natural gas is unavailable and their onsite fuel inventory is less than 16 hours for CTs and 32 hours for steam.
The changes were made to align with existing language in the PJM Operating Agreement for designating fuel-limited resources as maximum emergency.
First Primary Frequency Response Evaluation Reveals Low Participation
Most online resources don’t provide primary frequency response (PFR), a PJM analysis concluded.
PFR is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.
Primary frequency response by unit | PJM
Danielle Croop, a senior engineer in PJM’s generation department, said 583 units with capacities of 50 MW or greater were evaluated for PFR across five events in late 2018 and early 2019. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-mHz deadband, frequency stays outside the +/- 40-mHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 mHz.
No more than 20 resources provided PFR during the selected events, PJM data show. More than half remained offline and another third did not respond, Croop said. When pressed as to whether the analysis meant generators were performing poorly, she said only that clearly more follow-up is needed to fully understand why units did not respond as anticipated.
“I will say there is a concern here because we looked at 583 units, and the majority of them are not responding,” she said.
BTM Generation Rules Preview
PJM will soon bring rule changes for non-retail behind-the-meter generation (NRBTMG) to the OC for endorsement.
NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.
PJM’s rules on such resources resulted from a 2005 settlement agreement (EL05-127), before development of the RTO’s capacity market and CP constructs. NRBTMG resources can be called upon during the first 10 maximum generation emergencies annually, while CP resources are required to perform during all performance assessment intervals (PAIs). BTM operators that fail to perform face reduced netting benefits. In 2006, the grid operator identified about 400 MW of NRBTMG.
Terri Esterly, PJM’s senior lead engineer for capacity market operations, said manual changes are ready for stakeholder review. The revisions grew out of a problem statement and issue charge that showed PJM can’t accurately account for how much NRBTMG contributes to the grid, particularly with the growth of solar and other distributed resources. (See “PJM Continues Review of Non-retail BTM Generation Business Rules,” PJM OC Briefs: Feb. 5, 2019.)
Updates to Manual 13 show the phrases “maximum generation emergency action” and “deploy all resource action” have been identified as triggers to load NRBTMG. Updates to Manual 14D Appendix A include revisions to the business rules to clarify the reporting, netting and operational requirements of NRBTMG.
Southern California Edison’s request for a huge transmission rate adjustment based on potential wildfire liability got a tepid reception from FERC on Tuesday (ER19–1553).
The commission tentatively accepted the increase, per its customary procedure, but postponed any change for the maximum five months and set it for an evidentiary hearing, while encouraging the utility and protesters to settle. Protesters in the case include the California Public Utilities Commission, whose recommendations FERC largely followed.
FERC said its preliminary analysis indicated SCE’s proposed 2019 transmission revenue requirement could be unjust and unreasonable — and may provide the utility “substantially excessive revenues.”
SCE is seeking a whopping 17.62% return on equity, which includes the 11.12% base ROE the utility requested last year plus a 50 basis point incentive adder for CAISO participation, along with an additional 600 basis point cushion to account for the costs of wildfire liability. If approved, the new rate would boost SCE’s annual transmission revenues by nearly $290 million.
Investigators found that Southern California Edison power lines sparked the Thomas Fire, which killed two people in Dec. 2017 and led to mud flows that killed 21 more. | U.S. Forest Service
SCE said in its April 11 filing its proposal was based on “dramatic material changes to SCE’s regulatory and financial conditions that have occurred” since the utility filed its currently effective formula rate in October 2017.
Those changes include massive and deadly wildfires in SCE’s service area and the potential for multi-billion-dollar costs based on California’s strict liability standard for utility-sparked fires, known as inverse condemnation. (PG&E, which intervened in the case, faces similar circumstances and filed for bankruptcy in January due to wildfire liability.)
“Beginning in December 2017, several wind-driven wildfires impacted portions of SCE’s service territory and caused substantial damage to both residential and business properties and service outages for some of SCE’s customers,” SCE wrote. “California has unique inverse condemnation laws. These laws provide that an electric utility will be held strictly liable for property damages and legal fees if its facilities are the substantial cause of a fire regardless of fault and even if the utility was fully compliant with all applicable rules and regulations and acted reasonably.”
“As a result of these laws and recent fires, SCE is exposed to significant potential wildfire damage claims,” the utility said. “In 2017, the California Public Utilities Commission (‘CPUC’) issued a decision holding that it could preclude a utility from recovering these court-assigned costs if it finds the utility was not prudent, even if the source of the alleged imprudent conduct was not directly the cause of the fire.”
FERC, which has oversight of SCE as a transmission owner, and the CPUC, which regulates the utility’s distribution system, have different standards for cost recovery, SCE pointed out. The difference could be a costly one.
‘Atypical’ Risk
State investigators determined SCE equipment started the 282,000-acre Thomas Fire in December 2017 that killed two people and led to mudslides that killed 21 more in Ventura and Santa Barbara counties. The California Department of Forestry and Fire Protection (Cal Fire) has listed the official cause as “line slap,” whereby electrical conductors contact each other or adjacent components. (See Edison Takes Partial Blame for Wildfire in EarningsCall.)
The Woolsey Fire in November 2018 killed three residents, destroyed 1,500 structures and burned 97,000 acres in Los Angeles and Ventura Counties. Its cause remains under investigation, though lawsuits have blamed SCE. The fire began near an SCE substation where a nearby circuit experienced problems shortly before the fire started, the Los Angeles Times reported.
In its filing with FERC, SCE argued its conventional base ROE does not reflect “extraordinary wildfire liability risks.” The utility submitted testimony concluding an ROE allowance of 600 basis points added to its base ROE would match the size and insurance cost of the wildfire problem.
The Thomas Fire left a massive burn scar across coastal Southern California. | NASA
“SoCal Edison states that authorizing such an amount on top of the base ROE would provide additional investor returns needed to account for the severe wildfire risk SoCal Edison faces,” FERC wrote.
In its protest to FERC, the CPUC called SCE’s proposed increase “extraordinary” and noted SCE’s request “touches upon similar issues in proceedings pending before the CPUC.”
“SCE’s filing would result in a retail revenue requirement of $1.328 billion, compared to the current revenue requirement of $1.038 billion,” the CPUC wrote. “SCE’s proposed rate increase is primarily tied to a proposed return on common equity (‘ROE’) of 18.4%, an unprecedented proposal which would create a windfall to SCE investors, at an unacceptable cost to SCE’s captive customers, in violation of the Federal Power Act. This proposed formula will result in unjust and unreasonable rates in 2019 and beyond and should be rejected.”
The CPUC said it calculated the higher rate based on an ROE of 17.12%, a 50 basis point incentive adder for membership in the CAISO and project-specific adders ranging from 75-125 basis points.
“The enormous increase in the rate of return request is due primarily to a 600 basis point adder ascribed to the legal issue in California of ‘inverse condemnation’ and the wildfire liability risk it imposes on California utilities,” the California regulator said. “The CPUC does not object to SCE raising this issue, but it does object to the magnitude of the proposed risk premiums, which stems from SCE’s departure from accepted cost of capital methods used to develop that estimate.”
“The wildfire liability issues in California, including state law on inverse condemnation, are complex and do create atypical utility risk,” the CPUC wrote. “It may be the case that a reasonable treatment of this risk as part of rate of return should be considered. That said, the proposed 600 basis point adder is unreasonably large, violates the upper end of the zone of reasonableness (for an electric utility proxy group, which is FERC practice) and is not consistent with the available financial metrics for SCE and its parent Edison International.”
The CPUC said SCE had overstated its risk. Though its credit rating fell due to fire liability, it remains in investment-grade territory, and its stock price has been relatively stable, the CPUC contended. “The presently observed risk indicators for SCE are not as dire as portrayed by company witnesses,” it said.
‘Utility Imprudence’
Protesters Public Citizen and The Utility Reform Network, both nonprofit public interest groups, advanced similar arguments.
“SCE misrepresents the liability regime in California, and the utility is not at risk for wildfire liability absent a finding that it was imprudent in managing its system [under the prudent manager standard],” they said. “FERC should not condone utility imprudence by insuring the company against its own negligence. Moreover, SCE has raised these very same issues in its recently filed cost of capital proceeding at the California Public Utilities Commission.”
“Since any alleged financial risk due to wildfires depends on California-specific factors and policies, and any such risk is caused primarily by ignitions on the distribution system, this commission should refuse to rule on such issues or authorize increases in ROEs for transmission investments and instead should allow the California PUC to evaluate these claims,” the groups argued.
FERC said it hopes the parties will settle prior to a hearing.
“While we are setting this matter for a trial-type evidentiary hearing, we encourage the parties to make every effort to settle their dispute before hearing procedures are commenced,” FERC wrote. “To aid the parties in their settlement efforts, we will hold the hearing in abeyance and direct that a settlement judge be appointed.”
VALLEY FORGE, Pa. — The 90-day clock for stakeholders to work out how PJM will unwind $100 million worth of financial transmission rights (FTR) settlements begins June 19, said PJM legal counsel Jen Tribulski.
The update comes after FERC issued an order June 5 that encouraged conflicting parties to hammer out disagreements ahead of a scheduled paper hearing under the guidance of a settlement judge, who will report progress on the discussions to the commission at the 45- and 90-day marks (ER18–2068). A one-time extension may be granted for 30 days, FERC said. (See FERC: PJM Settle Disputes Before GreenHat Hearing.)
“During the settlement proceedings, all issues are on the table,” Tribulski said. “It doesn’t have to be just the six [issues PJM raised in its request for clarification]. If we go to hearing, it’s limited to just the six issues.”
Stakeholders expressed a mix of confusion and frustration over the ruling, with most unsure of what’s left to settle considering many were in agreement with PJM’s initial waiver request.
“The real problem is FERC just making the wrong decision and setting us down a path that PJM said is untenable,” said Carl Johnson, of the PJM Public Power Coalition. “You asked them to clarify their own rules, so I think it’s unrewarding that FERC is going to ask us to fix it among ourselves.”
5-Minute Dispatch Problem Statement Endorsed
Stakeholders gave near-unanimous support for the Independent Market Monitor’s problem statement to review processes for real-time security-constrained economic dispatch (RT SCED) and market pricing that PJM uses to send dispatch signals to generators and calculate LMPs. (See “Monitor Presents Updated 5-Minute Dispatch Problem Statement” in PJM MIC Briefs: May 15, 2019.)
Siva Josyula of Monitoring Analytics said a publishing price delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.
Education about RT SCED will begin in the MIC next month.
Electric Storage Participation Rule Changes
PJM presented more manual revisions for electric storage participation rules in compliance with FERC Order 841.
In Manual 11: Energy & Ancillary Service Operations, section 2.3.4B was added to explain how electric storage resources (ESRs) would participate in the markets, including clarification that the resources can sell in the energy, capacity and ancillary markets if they are technically capable of providing those services. It also provides information on dispatch and pricing, bid parameters and clarifies that stored MWh are billed at LMP as wholesale. Staff also added definitions for defined modes and the opt-in and opt-out processes and updated ESR hourly limits.
In Manual 18: PJM Capacity Market, staff updated the definition of capacity storage resource to include ESRs that participate in the reliability pricing model or are “elsewhere treated as capacity in PJM’s markets such as through a fixed resource requirement capacity plan.” Revisions also clarify that ESRs may not receive peak load contributions for energy they sell back to the grid.
Laura Walter, a senior lead economist for PJM, said the purpose of the revisions — and many more anticipated in other manuals — is to open up markets for ESRs and ensure parameters allow such resources to operate effectively.
PJM’s ESRs include approximately 5,000 MW of pumped hydro and 310 MW of battery storage, she said. The resources will be allowed to offer into both the day-ahead and real-time markets and will be modeled as continuous resources with the ability to self-manage their own state of charge.
PJM will seek MIC endorsement at the July 10 meeting.
CARMEL, Ind. — MISO will one day see a proliferation of electric vehicles, just don’t expect them to begin plugging in en masse before millennials begin hitting midlife crises.
The region served by MISO can expect to see significant EV penetration of anywhere from 1 to 12 million vehicles by 2039, according to a Lawrence Berkeley National Laboratory impact study prepared for the RTO.
MISO policy studies engineer Aditya Jayam Prabhakar opened his June 12 presentation on the study before the Planning Advisory Committee with an anecdote describing how his neighbor on one side had recently purchased a red Tesla model, while his other neighbor is also considering buying a Tesla.
“I’m going to be addressed as the guy between two Teslas,” Prabhakar joked.
But he said the story illustrates that “what was once was out-of-reach is now becoming attainable.”
If EV adoption revs up, MISO could see as many as 36 million EVs in the footprint if “MISO turns into San Jose,” Prabhakar said. But that’s an extremely unlikely case, he pointed out.
“There’s obviously a very high range,” Prabhakar said.
The likeliest range of future EVs, he said, lies somewhere among the study’s “low,” “base” and “high” case scenarios of 1.6 million, 4 million and 12 million vehicles, respectively, by 2039. To come up with its estimates, Berkeley used a combination of MISO and state-level data, 2018 projections from Boston University researcher Peter Fox-Penner and figures from the U.S. Energy Information Administration.
The MISO footprint currently contains only about 70,000-80,000 EVs, Prabhakar said.
“That’s a very small number compared to where we could be in the future,” he said
The study shows that if left uncontrolled, EV charging stands to steadily increase peak loads and the ramps needed to accommodate those peaks. However, if EV charging is controlled, it can deliver “significant load shaping grid services,” MISO said.
Controlled charging can occur in one of two ways, the study explained. Under “unidirectional” control, the flow of power to the vehicle can vary over the course of a charging session based on a timer, price signal or other set of rules based on grid conditions. “Bidirectional” control offers all those same features, while additionally allowing power to flow from the vehicle to the grid, helping to alleviate grid stress during periods of peak consumption.
MISO also noted that managed EV charging can help mitigate the daily load troughs and morning and evening ramps that increased renewable use can exacerbate.
In the extreme, 36-million vehicle case, uncontrolled EV charging “dominates loads throughout the day” and could add about 40 GW to MISO load by mid-2038. MISO’s average summer load last year was 86.6 GW.
“Preparing for EV impacts and their charging is a really great thing to start thinking about,” Prabhakar said. ” … This is uncharted territory in terms of what can happen; there’s so much that can happen.”
“I think EVs are a question of not if, but when,” Wabash Valley Power Association’s Matt Dorsett said. “What are the next steps for MISO? It’s certainly on our radar, and I think it’s coming quicker than we’d like.”
Prabhakar said MISO can begin adding more sophisticated EV load shapes in planning models. He said previous attempts to model future EV use boiled down to simple energy use increases.
“This is a more engineering-based approach,” he said, referring to the load-shaping approach.
Veriquest’s Dave Harlan asked whether MISO would also consider that, by 2040, several MISO generators could have already installed storage that would already serve to flatten load.
Prabhakar agreed potentially disruptive technologies like storage and EV charging should be considered together.
Multiple stakeholders also asked MISO to keep an eye on burgeoning, ultra-fast technology that can fully charge a vehicle within minutes, placing extra demand on the grid.
PHILADELPHIA — “There’s probably no topic that inspires more emotions” than electromagnetic pulses (EMP), says Electric Power Research Institute CEO Michael Howard.
An Amazon search of the topic shows why, he said at the Edison Electric Institute’s 2019 conference here Tuesday. “I haven’t done this in a little while, but I know three years ago, the first 19 of the top 20 books [on EMPs] were science fiction. And [they talk] about the end of the world,” he said. “It’s not a good day, but it’s not the end of the world when you have an EMP blast. That emotion creates hysteria. It creates unrealistic understanding about what EMP is really about and what we need to do to mitigate the impact.”
In April, EPRI released a study that concluded a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, months-long blackout some observers have warned of. (See EPRI Report Downplays Worst-Case EMP Scenario.) On Wednesday, a NERC task force met for the first time publicly to discuss the EPRI research and President Trump’s March 26 executive order directing the federal government to protect the nation’s critical infrastructure from EMPs. (See EMP Task Force Takes ‘First Bite of the Elephant.’)
Mark P. Harvey, the National Security Council’s senior director for resilience policy, told the EEI crowd the executive order was long overdue.
“It’s been a known threat for a long time, and we get a lot of questions that say, ‘Has the threat picture changed? Is somebody now more capable? Why are you doing this now?’” said Harvey. “Frankly, it was time to take action. We’ve known about this for so long, but we haven’t had decisive action.”
Harvey said those who consider the risk of a high-altitude EMP (HEMP) remote shouldn’t dismiss the threat.
“Twenty-five years ago, the Department of Energy proved you could take material that’s already posted online and build an EMP generating device for as little as $50 with a trip to Sally’s Beauty Supply and Home Depot and knock out power to a building about this size,” he said, referring to the Marriott Hotel where EEI met.
“Don’t think just missiles over the poles, high-altitude nuclear detonation when you’re thinking about EMP. … There are ways of doing this on smaller scale with flux compression devices [or] high-powered microwave devices that could be applied against particular critical infrastructure.”
Harvey said the potential impact of such an attack has been magnified because “our critical infrastructure not only is more interconnected than it ever has been, it is now to a point where its operating with as little excess capacity as possible. It is almost maxed out within our electric sector, our communications sector, our transportation networks. So, there is little margin for error and little margin for loss across all of those critical infrastructure sectors, especially when you consider how connected they are and that you can have cascading impacts.”
Moderator Caitlin Durkovich, a director at Toffler Associates and the Department of Homeland Security’s former assistant secretary for infrastructure protection, said she is amazed by the lack of awareness about the threats of EMPs and geomagnetic disturbances. “There are people who very much think this is a thing of science fiction. They would laugh and say, ‘Really? There’s something called space weather?’”
“We are very good at planning for what’s in the rear-view mirror,” she said. “We have to get better at planning for what’s on the horizon, and even the unimaginable.”
Robert Blue, CEO of Dominion Energy’s Power Delivery Group, noted his utility supplies power to the Pentagon and numerous defense contractors and military facilities, including the world’s largest naval base at Norfolk, Va. “And a large portion of the world’s Internet traffic goes through data centers that are ours … in Northern Virginia,” he added. “So, as we think about these issues, we feel like we have a particularly important role to play because of that customer base.”
Blue said Dominion began developing expertise and mitigation measures after a GMD event in March 1989 caused the failure of the Hydro Québec system and trips of capacitor banks that Dominion used to control voltage.
“We started off by changing the specs for substations — capacitors, transformers [to] make sure they have the ability to withstand GMD-type events. [We] improved our situational awareness … equipment changes, process changes,” he said. “That sort of view has transferred to much of what we do on other issues of physical and cybersecurity.”
David W. Roop, Dominion’s director of electric transmission operations and reliability, has become a national authority on GMDs and EMPs, testifying before Congress on the topic in February.
Harvey said utilities and other critical infrastructure providers are now in a role like that of police and firefighters after 9/11.
“We looked to cops and firefighters after 9/11 and said, ‘You’re on the front lines of the global war on terror,’ and they said, ‘Hold on, I’m not ready for that.’ We said, ‘That’s fine. We’re going to give you doctrine, we’re going to give you training, we’re going to give you tools. And they stepped up.
“Now you, your members, your colleagues, are on the front lines of the great power competition of the 21st century,” he told the audience. ” … The defining threat of this era is the asymmetric threat to critical infrastructure.”
PHILADELPHIA — Cybersecurity was the subject of two panels at the Edison Electric Institute’s 2019 conference this week. Here’s some highlights of what we heard.
Hawaiian Electric Industries CEO Connie Lau, who moderated a June 10 panel on grid security, said her utility is a cyber target in part because the Honolulu area is home to the Defense Department’s Indo-Pacific Command (USINDOPACOM).
“The U.S. watches 52% of the world’s surface from our little island,” she said. ” … If our adversaries wish to compromise INDOPACOM’s mission readiness, it’s unlikely they’re going to go directly after the DoD but more likely they might target the critical infrastructures that service those bases.”
“The good news is that our industry’s partnership with the government has never been stronger, led by ESCC [the Electricity Subsector Coordinating Council],” added Lau, who is chair of the president’s National Infrastructure Advisory Council. “Our sector’s coordinating council is considered the best around and a model for other sectors.”
Brian Harrell, the Department of Homeland Security’s assistant director for infrastructure security in the Cybersecurity and Infrastructure Security Agency (CISA), agreed.
“When you have CEOs in a room and we’re having conversations about storm restoration … whatever the issue is, we know that when we can engage the senior leaders, things all of a sudden happen. And we don’t necessarily see that in other critical infrastructure sectors.”
Harrell joined DHS after stints as NERC’s director of critical infrastructure protection programs, where he headed the Electricity Information Sharing and Analysis Center (E-ISAC), and as managing director of enterprise security for Duke Energy.
Harrell recalled when NERC began planning for its first GridEx in 2011, “not a whole lot of folks wanted to play in a cybersecurity exercise with their regulator. And now I think we’ve been able to get over that hill. … The reason we do this is for us to collectively — from a government and industry response — get better. To ask ourselves the hard questions under blue sky conditions and not necessarily when things go wrong. We do not want to be passing around business cards in the midst of [a] crisis.”
Harrell warned against the risk of “security fatigue.”
“We’re bored of talking about information sharing at this point. But in reality, it’s one of the most critical things we do,” he said.
He also called on the industry to become more proactive in anticipating threats. “We cannot [be] constantly bolting security on to some of our systems and plans that we have. We need to get ahead of the adversary.”
Adrienne Lotto, deputy assistant secretary in the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER), discussed DOE’s Cyber Analytics Tools and Techniques (CATT) and Cybersecurity for the OT Environment (CYOTE) projects, which hope to improve situational awareness.
“Threats for the sector today are forcing us to think differently and act differently to ensure what we are telling our systems to do is actually what’s happening out on those systems,” she said. “Right now, there’s no way to know with any degree of confidence that an app, a switch or a router or anything is doing precisely and only what you purchased it to do.”
A Pawn
Duke Energy Chief Information Security Officer Dennis Gilbert, who moderated a June 11 panel on the challenges of the interconnected grid, said his company, like other utilities, has become “a pawn in the geopolitical struggle.” He lamented hackers have turned the dark web into a marketplace for “cybercrime as a service.”
Robert M. Lee, CEO of cybersecurity company Dragos, said while experts have learned much about threats to industrial environments in the last five years, “a lot of our frameworks, regulation, best practices … [haven’t] adapted.”
“We’re actually using a lot of enterprise security strategies and then forcing them on the industrial side of the house. To actually take lessons learned, we’re going to have to do that as a community. We can’t just wait for [National Institute of Standards and Technology] to put out the latest thing or for [the] NERC CIP [standard] to be adapted. It’s going to be the electric sector leadership that steps up and takes their role and says here’s what we’re learning out in the field. And here is what we think the government can do on top of that.”
“What keeps me up at night is not Duke or Southern Co. going down; I think they have generally good security,” he continued. “What concerns me is distribution. [If hackers cause] a 30-minute power outage …. Congress is going to freak out because the public is going to freak out. They’ve heard everything from Ted Koppel’s book [Lights Out] to [predictions] about we’re all going to die. … If we don’t get a control on that narrative, the fear alone could outpace what we’re trying to accomplish.”
Frank J. Cilluffo, director of Auburn University’s McCrary Institute for Cyber and Critical Infrastructure Security, said industry and government have “spent five years sniffing each other. I think the trust is there now,” he said.
In addition to those from China and Russia, Cilluffo warned of risks from North Korea and Iran. “What they lack in ability, they make up in intent,” he said.
Steven Dougherty, global leader of IBM Security’s Energy, Environment and Utilities group, warned social engineering tactics are becoming more automated. “Look at the work that was done on BlackEnergy. That was a team of [about] 35 different coders who worked on that malware. The sophistication that we’re seeing in this space is significantly greater than in the past.”
President Trump’s March 26 executive order calling for actions to protect the grid from electromagnetic pulses (EMPs) has “troublesome” timing requirements, a Department of Homeland Security official told a NERC task force at its first public meeting Wednesday.
The task force was formed in response to the Electric Power Research Institute’s April report on EMPs, which concluded a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, months-long blackout some observers have warned of. (See EPRI Report Downplays Worst-Case EMP Scenario.)
The task force, which met at NERC headquarters in D.C., was charged by the board of trustees to determine if any immediate mitigation should be taken and to identify additional research needs, said Vice President of Standards Howard Gugel. It is expected to make any recommendations for guidelines or other actions by the third quarter.
A Department of Homeland Security official said President Trump’s March 26 executive order on EMPs has “troublesome” timing requirements. | Department of Homeland Security
Using Physics to Bound Risk
Scott Backhaus, the Department of Homeland Security’s coordinator for electromagnetic pulse impacts on critical infrastructure, gave a briefing in which he described the “huge timing challenge” posed by the president’s executive order and talked about the need to revise the definition of critical infrastructure.
Backhaus urged the task force to “use physics and engineering to constrain our analysis” and avoid overestimating the risk.
“Let’s incorporate the engineered nature of the infrastructure systems. … Impacts may already be mitigated by existing control systems, redundancy backups, hardening that’s already in place … and existing restoration plans.”
“EMP is one of many threats, so we need to develop our best estimate of risk from EMPs and [geomagnetic disturbances] to place them in context of the other risks that the bulk system faces,” he continued. “In a world of constrained resources, if we overestimate one risk, that will suck all the air and all the money out of the room, and it could potentially degrade our ability to harden and respond to other risks.”
Seeking a Government Consensus
The Department of Energy (DOE), the Defense Threat Reduction Agency (DTRA), DOE’s nuclear weapons labs and DHS are working to develop a U.S. government consensus on intelligence- and science-based EMP threats that it can declassify and share with the industry, Backhaus said. “What’s the explosive package? How is it going to be delivered? How high can it be delivered? What’s the worst-case delivery?”
The analysis will be based on several EMP “waveforms,” to account for threats from multiple actors with a range of nuclear weapons technologies. “We need to address a sufficient number of different technologies [so] that we cover the span of our adversaries,” Backhaus explained. “We can estimate the impacts across the entire threat spectrum. We’re putting the decisions about how much risk you’re willing to take … to the people who spend money — the utilities.”
One task force member asked how different the current waveforms are from those developed in the 1950s based on the Soviet Union’s capability. “No comment,” Backhaus responded. “No comment,” he repeated as the questioner attempted a follow-up query.
Gugel asked Backhaus if NERC members will be able to obtain unclassified information on peak magnitudes or the duration of EMP events. “We’ve got to make sure we’re in the right ballfield,” Gugel said.
“How we remove the classified information is still a topic of discussion,” Backhaus said.
Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | Electric Power Research Institute
‘Huge Timing Challenge’
Backhaus noted the executiveorder calls for development of vulnerability impacts at the 15-month mark from March 26. “But for some reason, technology mitigation options and regulatory incentives come in month 12. So, we will not have finished any vulnerability or impacts by the time we have to suggest mitigation and regulatory incentives and non-regulatory incentives. There’s a huge timing challenge here.
“I need to give FEMA some guidance on the size of power outages that would be expected from an … EMP effect. Do they need to update their plans or are their plans sufficient to handle an outage of that size?” he continued. ” … FEMA needs to go and update its response recovery plans in month six. We still don’t even know what the impact is.”
“The timing wasn’t determined by DHS. It wasn’t determined by DOE,” Backhaus said.
Backhaus said DHS’s only option is to use existing impact studies that are sound and consistent with each sector’s best practices. DHS and DOE are currently peer-reviewing recent EMP impact studies from different entities, an effort to quell the “controversy” over the proper model to use.
Identifying Critical Infrastructure
Backhaus said DHS’s traditional criticality approach focuses on singular assets or tight clusters of assets, such as certain chemical plants and some banking and finance. “The threshold for calling them critical is when there’s a significant national or regional impact if one asset — or one cluster of assets — goes away.”
That, he said, is not appropriate for electric assets. Bulk power systems are highly redundant and “don’t really have singular assets. You can lose a large multi-gigawatt generator and … it impacts your operations, but you can operate through because you have redundancy both in the generation fleet and in the [transmission] network.”
The DHS approach also fails to recognize common-mode disruptions of components that are replicated throughout the networks.
“A lot of the work that [EPRI’s] done is on protective relays. Those would never be identified in this approach as a critical assets because the failure or any one of them is not that significant on the national or regional scale.”
He proposed adding to DHS’s criteria the identification of regional scale infrastructure networks whose disruption would create significant impacts. “So, things like ERCOT, … WECC, or [CAISO], however it makes sense to break those down,” he said.
He would also identify local distribution companies with common architecture that are replicated nationwide.
EPRI Study
EPRI’s Randy Horton briefed the task force on its April study, which recommended mitigation measures including shielding cables, enhanced grounding and modifications to substation control houses.
Horton acknowledged the study was limited to the grid and transformers and did not examine potential impacts on generation. “Trying to solve the EMP problem on the bulk power system is very much like trying to eat an elephant,” he said, noting the study’s call for additional research. “You’ve got to start somewhere, and the transmission system is a very important aspect of resiliency.”
Illustration of an substation control house hardened against an E1 EMP | Electric Power Research Institute
Horton said the study found the impact of an E-3 pulse — a very low frequency pulse similar to severe geomagnetic disturbances (GMDs) although much shorter in duration — would be a voltage collapse in “a large region … on the order of the 2003 blackout, maybe a little bigger than that.”
EPRI is now conducting 18- to 24-month field trials of hardening measures at 17 U.S. utilities. Horton said the trials hope to prevent unintended consequences from the measures, such as protective system misoperations.
“There’s lots more work to be done,” he said. “We’re not finished by a long shot.”
Task Force Membership
The task force members, selected from names submitted by trade groups, include representatives from utilities Southern Co., American Electric Power, Dominion, Exelon, TVA and Xcel, along with the New York Power Authority, the NASA Goddard Space Center, FERC’s Office of Electric Reliability and the National Rural Electric Cooperative Association. The task force is not accepting additional members, said NERC’s Soo Jin Kim, to keep its numbers manageable.
It will hold a technical workshop on July 25 at NERC headquarters in Atlanta, she said.
Gugel said although the task force hasn’t been formalized with a reporting relationship to a standing committee, it will probably report to the Operating Committee, the Planning Committee or both. (See Standing-room Only for NERC EMP Meeting.)
