PJM announced Duane’s resignation, effective immediately, via email Monday. In the release, the RTO said Duane will seek other opportunities after more than 16 years with the organization.
“We are grateful to Vince for his many contributions to PJM and its stakeholders over the past 16 years,” interim CEO Susan Riley said in a statement. “As a member of the PJM Board of Managers, I worked with Vince from the time I joined the board and have enormous respect for his legal perspective. The entire PJM community thanks Vince for his many contributions to PJM.”
Deputy General Counsel Chris O’Hara will assume the role of vice president, general counsel and corporate secretary with responsibility for law and compliance, effective immediately, PJM said.
“It has been my honor and privilege to serve PJM’s employees and members for more than 16 years,” Duane said. “I am proud to have been part of such an outstanding team doing extremely important work, and I know PJM will continue to forge ahead with innovation, integrity and outstanding service to its members.”
Chris O’Hara, PJM | PJM
Susan Buehler, PJM spokesperson, didn’t elaborate much further on Duane’s departure, except to say that it “was purely his decision” and that he was ready to move on and “do something else.”
Duane is the fourth top executive to leave PJM this year, following the resignations of CEO Andy Ott, CFO Suzanne Daugherty and Vice President Denise Foster. In September, Riley announced the restructuring of the State and Member Services Division, previously led by Foster and now headed by Jen Tribulski, senior director of member services, and Asim Haque, executive director of strategic policy and external affairs.
Several key leaders within PJM also received promotions over the summer, announced at the time of Ott’s resignation. (See CEO Andy Ott to Retire.) The organization also hired Nigeria Poole Bloczynski as its first chief risk officer in July and hopes to choose a new CEO before the end of the year. (See PJM Names Chief Risk Officer and “CEO Search Continues,” PJM MRC Briefs: Sept. 26, 2019.)
FERC encouraged PJM’s transmission owners to settle disputes over the sector’s proposed Tariff attachment that revises outdated border and non-zone service rates using a methodology that several members find flawed and unreasonable.
The filing, sent to FERC in June, updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside PJM’s boundaries but served from within the RTO — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM (ER19-2105). In the filing, TOs said under existing rates, last updated in 2004, it’s unclear if border rate customers “have been consistently charged transmission enhancement charges (TECs)” because of the ambiguity around which specific TECs apply to border service.
“The PJM TOs argue that the proposed revisions will end the cross subsidy that zonal NITS customers in PJM have been providing to border rate and non-zone service rate customers because revenue from customers taking service under each of these rates is either directly or eventually credited back to zonal NITS customers,” the commission noted in its order.
The proposal would not increase the total cost of providing transmission service in PJM because the increases to border and non-zone service rates will be offset by a decrease for zonal NITS customers, the TOs said in their filing.
FERC accepted the TOs’ filing Nov. 5, subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.
Contentions Raised
In proposing the rate revision, TOs wanted to clarify that PJM’s border service includes service to a point of delivery at a merchant transmission facility (MTF) that provides service to a neighboring transmission system — an unnecessary explanation, according to some of the protesters in the proceeding.
The New York Power Authority suggested the clarifying language “is an attempt to create a separate and unjustified classification of customers for purposes of extracting a higher point-to-point transmission service rate from such customers.”
Linden VFT, a New Jersey-based MTF, said the new methodology would increase its border rate charges from $6 million annually to roughly $16 million, potentially forcing the company into insolvency because of “fundamental changes” to its business model. It also objected to a formula that it insists charges the company for lower-voltage transmission facilities “it does not use.”
The TOs offered a solution for double charging of MTFs with firm transmission withdrawal rights (FTWRs): create a credit that would remove the cost of those TECs paid in connection to a facility’s FTWRs from the cost of border rate service.
The Long Island Power Authority argued the crediting mechanism will not work, and the Neptune Regional Transmission Authority supported the claim, noting that the TOs “crediting mechanism is structurally flawed and would result in MTFs with FTWRs and their customers being charged twice for the same allocation of [Regional Transmission Expansion Plan] charges.”
FERC Weighs in
FERC dismissed Linden’s argument that the proposed border rate would charge the company for lower-voltage transmission facilities it does not use, saying “the border rate reflects the fact that a transmission customer may take border rate service from any point within PJM, and that the entire PJM transmission system, including lower-voltage transmission facilities, supports the export transactions.”
“The border rate service, therefore, permits the exporter to access generation anywhere in PJM and such transmission may utilize any of the PJM facilities, including lower-voltage lines,” the commission concluded.
FERC also allayed concerns over the TOs clarifying language on the definition of border service, saying that it is just and reasonable and aligns with commission precedent on the definition of “through and out service.”
Other concerns over whether the proposal meets the standards for formula rate protocols were also dismissed. FERC said because the stakeholders can contest PJM TOs formula rates, there is no need for additional protocols regarding the proposed composite rate. The commission did agree, however, that the TOs’ filing “lacks clarity regarding the process by which parties can challenge or confirm PJM’s calculation of the border rate from the PJM TO’s formulas.”
FERC said a settlement judge will be assigned within 15 days of the filing. The appointed judge will report to the commission within 30 days concerning the status of settlement discussions. At that time, the judge can recommend additional time for settlement negotiations or commence a paper hearing.
The commission granted late-filed motions to intervene from Exelon, PPL and Helix Ravenswood.
NYISO’s Business Issues Committee on Wednesday voted unanimously to recommend that the Management Committee approve Tariff changes intended to help speed up the interconnection process.
Thinh Nguyen, senior manager for interconnection projects, presented the proposed changes, which seek to expedite the class year portion of the interconnection study and limit the potential for one or two projects to cause delay for other projects.
NYISO is proposing to:
require deliverability evaluation in system reliability impact studies;
remove additional system deliverability upgrade studies from the class year study;
conduct expedited deliverability studies for capacity resource interconnection service (CRIS)-only projects; and
tighten CRIS expiration rules to prevent the retention of CRIS by facilities not participating in the capacity market.
Nguyen noted that stakeholders were keen to ensure the proposal would not change the qualities of the current process most important to them, including:
the identification of system upgrade facilities for projects to reliably interconnect, including detailed design, engineering and construction estimates;
provision of binding, good-faith cost estimates that provide reasonable closure on upgrade costs; and
equitable allocation of upgrade costs.
NYISO intends to make many of the proposals effective for Class Year 2019.
A sample timeline of expedited deliverability of the class year study | NYISO
Competitive Entry Exemptions
The committee also voted unanimously to recommend that the MC approve Tariff changes to make competitive entry exemption (CEE) available to requests for additional CRIS megawatts in a manner consistent with the underlying rationale for the exemption.
Senior ICAP Mitigation Analyst Jonathan Newton presented the proposal, which includes a change in the consequences of withdrawing a CEE request or providing false and misleading information.
The changes also modify the CEE rules in a way that could facilitate the repowering and replacement of existing generators by allowing existing portfolio owners that have entered into competitive short-term hedging contracts to qualify for the CEE.
“The changes are a reasonable way to let people move forward without penalizing normal commodity hedging,” one stakeholder said.
NYISO intends to make the proposed rules effective for Class Year 2019 projects, Newton said.
If the MC approves the queue changes this month, and the Board of Directors approves them in December, the ISO anticipates making the filings with FERC by Dec. 20 and seeking orders from the commission during the third week of February 2020.
More Granular Operating Reserves
The BIC discussed a proposal to implement local reserve requirements in certain New York City (Zone J) load pockets.
Market Design Specialist Ashley Ferrer presented the proposal, as recommended by the Market Monitoring Unit, including the modeling of the requirements based on N-1-1 reliability criteria.
Load pockets in Zone J are areas constrained by load levels and generation capability, as well as by transmission-supported import levels into the pocket. The structure and boundaries of each load pocket varies based on load, generation and transmission imports, Ferrer said.
New York Control Area operating reserves | NYISO
The ISO last June established a reserve region in Zone J based on a market design approved by stakeholders in March.
NYISO is proposing to establish operating reserve demand curves for each load pocket that assign a $25/MWh value to the proposed reserve requirements. The ISO proposes 30-minute reserve requirements of 325 MW in Astoria East/Corona/Jamaica; 225 MW in Astoria West/Queensbridge/Vernon; and 250 MW in Greenwood/Staten Island.
“This issue is not prioritized in 2020, but we still consider it important, and it could go forward conceivably in 2021,” said Rana Mukerji, senior vice president for market structures. “We will actually bring forth the methodology [for an impact analysis] before conducting any consumer impact analysis [with respect to the proposal].”
Broader Regional Markets Report
In presenting the month’s Broader Regional Markets Report, Mukerji highlighted updates to two ongoing proceedings.
The first item concerned five-minute real-time dispatch transaction scheduling with Hydro-Québec (HQ) across controllable interties at the Chateauguay proxy.
The proposed plan includes a project to consider scheduling transactions on a five-minute basis with HQ, instead of either the 15-minute or hourly basis currently in effect using NYISO’s real-time commitment software. The ISO is targeting to complete a study of the potential enhancement in 2020.
The second item concerned an effort to clarify the minimum deliverability requirements for external capacity.
At the MC’s May 20 meeting, stakeholders approved enhancements to the performance requirements for external capacity suppliers in response to a supplemental resource evaluation, a proposal that became effective in August after FERC approval.
IPPNY’s Matt Schwall Elected as Vice Chair
The BIC elected Matthew Schwall as its incoming vice chair for 2019/20. Schwall is director of market policy and regulatory affairs for the Independent Power Producers of New York, where he has worked since 2014, and previously worked in various capacities at the New York State Assembly. He is earning a master of science in global energy management at the University of Colorado Denver.
SPP staff last week told the Seams Steering Committee that they have begun “very preliminary” interregional planning discussions with Canadian electric utility SaskPower.
Clint Savoy, the committee’s staff secretary, said a provision in the RTO’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. The discussions center on reliability needs, he said.
SPP and SaskPower share a direct tie through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota. The grid operator completed its first international transaction in December 2015 when it imported power from SaskPower during an emergency situation. (See SPP, SaskPower Make First International Trade.)
In February 2017, the Department of Energy granted SPP’s request to make electricity exports to Canada. The RTO told the department that it wanted to “address emergency assistance transactions” but that it doesn’t normally purchase from or sell to “such external entities.”
The authorization expires on Feb. 7, 2022.
FERC in 2016 approved SPP’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)
Pseudo-tie Revisions to SPP-MISO JOA
The SSC reviewed and made changes to a new pseudo-tie section of SPP’s joint operating agreement with MISO, addressing its neighbors’ continued deferral of dispatch decisions to its balancing authorities.
MISO has historically deferred to local BAs in making pseudo-tie decisions in the real-time transfer of a resource or load from its “native” BA to an “attaining” BA in a different location.
“There are some local balancing authorities taking the position that we’re not a BA, so we’re not going to execute it anymore,” Savoy said. “We thought it would be helpful to address this in the JOA and avoid those situations in the future.”
Savoy said staff have taken FERC-approved language from the MISO-PJM JOA as a starting point. SPP hopes to file the changes with FERC early next year.
M2M Settlements Swing in MISO’s Favor
Staff’s regular market-to-market (M2M) report indicated another slow month, with 41 permanent and temporary flowgates binding for a total of 664 hours and resulting in a $197,320 settlement in MISO’s favor.
| SPP
August’s numbers dropped to $64.1 million in SPP’s favor. The two seams neighbors began the process in March 2015. SPP has seen positive settlements in 40 of 54 months through August.
FERC accepted an agreement last week between CAISO and a Calpine plant to provide black start service, but it also agreed with the California Public Utilities Commission that more cost information was needed to determine if the deal was just and reasonable (ER19-2800).
The federal commission accepted the agreement effective Nov. 6 but required additional information to be presented at settlement hearings.
CAISO in 2016 determined it needed additional black start capability in the San Francisco Bay Area. It issued a request for proposals in June 2017 and ultimately selected a plan by Calpine to provide battery storage at the company’s gas-fired Russell City Energy Center in the city of Hayward.
The agreement between Russell City and the ISO — in which Pacific Gas and Electric, the transmission provider in Hayward, is also a participant — stipulates that the plant will collect about $7.4 million annually for five years to cover a $21.8 million capital investment and earn a reasonable rate of return. The plant owner will recover both the variable cost of providing black start service and the fixed cost of constructing the battery system.
Calpine’s Russell City Energy Center in Hayward, Calif. | Calpine
The variable cost represents the sum of a start-up charge, a fired-hours charge, greenhouse gas reimbursement, CAISO charge reimbursement, a performance test field support charge and a power plant outage cost reimbursement — all outlined within a schedule of the agreement. The contract also provides for Russell City to recover a “market revenue shortfall” if the revenues received during energy delivery are less than provided for by the schedule.
Russell City contends that CAISO’s competitive solicitation process guarantees that its rates, terms and conditions for black start service are just and reasonable. The ISO would have the option to renew the agreement for an additional five years after the contract expires.
In its comments to FERC, the CPUC said it supported the development of black start capability in the Bay Area but argued Russell City had not provided underlying cost information to support its filing. The state commission requested that FERC require Russell City to refile the agreement with underlying cost information, or alternatively accept the agreement but also determine that it does not set any precedent. FERC agreed with the CPUC’s concerns.
“Although Russell City, CAISO and PG&E represent that they exchanged information with CPUC about cost allocations during their negotiations of the agreement, that information has not been submitted into the record of this proceeding and therefore is not available for this commission to evaluate in determining whether the proposed rates are just and reasonable under Section 205 of the Federal Power Act,” the commission found.
Three years into the project to replace its market platform, MISO is now set to begin moving information to its new private cloud to begin testing.
MISO Director of Digital Delivery Foundations Kevin Larson said the RTO has completed much of the platform design work this year and will next year focus on upgrading technology infrastructure. He said it is making sure the platform is adaptable.
“We’re focused on the performance of the day-ahead clearing of the market engines: How fast can we do that with all the new [market] products and services?” Larson told stakeholders at a Market Subcommittee meeting Thursday.
He said MISO’s motto regarding the new cloud-based platform is “continuous integration, continuous delivery,” allowing for more regular improvements instead of “a few big deployments infrequently” using the existing server-based platform.
“As we look into 2020, we’re going to start migrating applications to the MISO private cloud,” Larson said. (See New MISO Platform Headed to the Cloud.)
MISO still expects to announce its preferred vendors on the platform build by the end of the year. So far, General Electric is still the major vendor.
“We’ve now had some early software deliveries for testing, and it’s been solid,” Executive Director of Digital Strategy Jeff Bladen told the Board of Directors in September.
Bladen said the quality of the software was up to MISO standards, and GE’s performance was much improved from its earlier delays. Board members at the time were pleased with the turnaround. (See “Vendor Delay on Market Platform Replacement,” MISO Board of Director Briefs: June 20, 2019.)
“We’re pleased to say early results are quite positive and encouraging,” CEO John Bear reported at the Oct. 22 Informational Forum.
MISO executives will deliver another market platform update at the Dec. 12 board meeting in Indianapolis.
ATLANTA — NERC’s briefing on its revised ERO Enterprise Long-Term Strategy last week prompted a discussion on whether it is feasible to apply cost-benefit analyses to reliability standards.
“We’ve been struggling with that issue for a while,” Hydro-Québec’s Sylvain Clermont said during the discussion at the Members Representative Committee’s quarterly meeting. “It’s like an oasis in the desert. We know there is an oasis in the desert. We even think we heard someone who saw the oasis. But nobody can quite find the oasis.”
“This is a really tricky area,” NERC Board of Trustees Chair Roy Thilly said. “Every survey we have done points out that stakeholder concern that cost really be considered in the standard [development] process.”
But doing a formal cost-benefit analysis before implementing a standard is difficult, Thilly said. “The effect on one entity may be very different than the effect on another entity, given where they already are in dealing with the issue.”
Industry can help NERC determine the least-cost way to accomplish the goal of a standard, he said. And an after-the-fact review once there is experience with a standard may be possible. “There may be much better information” then, he said.
Cost Effectiveness More Realistic?
Clermont agreed that cost effectiveness may be a more realistic goal.
“If there are two ways to implement a standard, which is more effective than the other one? That’s perhaps an easier question than is there a [positive] cost-benefit or is there a business case to develop a standard,” he said. “I would say that there is most likely never a business case to develop a standard.”
NERC CEO Jim Robb said the ERO is aware of the industry’s challenge in funding improvements for security and resilience “against the backdrop of flat to no load growth in many jurisdictions.”
“Everyone, when they cast a vote for a standard or against a standard, is making their own assessment as to whether or not it’s worth the [cost]. I don’t think we ever want to get to the point where we have a big econometric department at NERC … but I think we want to make sure we are reaching out and getting input from industry so the work we do is economically informed, even though that’s on the fringes of our mandate.”
State/Municipal Utility sector representative Carol Chinn of the Florida Municipal Power Agency said it would be helpful to “have compliance in the room when standards are developed.”
“I think there’s a lot of unknowns when standards are approved about how can you comply with it. These things are complex. When you look at, for example, CIP-003 … it’s [effective] Jan. 1. What are the expectations for compliance? What do we need to do?”
The strategy document was revised following comments from six industry groups, which also included the Edison Electric Institute and the ISO/RTO Council. It is set to be brought to an endorsement vote at the board’s Dec. 12 conference call after input from regional entities.
‘Focus Areas’
The new plan is based on four “Enterprise Value Drivers”:
Organizing and deploying top talent.
Developing and delivering innovative and risk-based programs and tools.
Collaborating effectively with industry and other stakeholders.
Maintaining independence and objectivity.
It identifies five “strategic focus areas”:
Expand risk-based focus in all standards, compliance monitoring and enforcement programs.
Capture effectiveness, efficiency and continuous improvement opportunities.
Assess and catalyze steps to mitigate known and emerging risks to reliability and security.
Build a strong, Electricity Information Sharing and Analysis Center-based security capability.
Strengthen engagement and collaboration across the reliability and security ecosystem in North America.
“We recognize that the electric system as it is today isn’t our grandfather’s electric system. … Lots of changes [are] coming at us in a lot of different directions,” Robb said. “So we always need to be thinking about … whether the programs we execute — many of which were designed 10 to 12 years ago — are still the right programs.”
The goal, he said, is “keeping eyes on the big issues [and] not getting distracted by the trivial.”
“Many of the things that we do have their roots in not only reliability and security but also … the resilience of the system, so you’ll see more references to resilience in the new document” than the 2017 strategy document it will replace, Robb said.
Funding
Andy Dodge, director of FERC’s Office of Electric Reliability, asked about the new plan’s reference to investigating “funding mechanisms” to support NERC’s mission.
The ERO Enterprise “Golden Circle” | NERC
Robb said that was a “placeholder” for potential programs that could be structured like the Cybersecurity Risk Information Sharing Program, which is funded by industry and the Department of Energy rather than the Federal Power Act Section 215 assessments that fund the ERO’s operations.
“A number of important issues that get identified in our various assessments … end up with a recommendation that says someone should do X and someone should do Y. And in many of those cases, we don’t really have any ability for establishing accountability as to who’s actually [going to] get it done,” Robb said.
“For example: new planning models … that would be necessary to address variability of resources on the system. … That’s not something we have the expertise to do in-house ourselves, but it’s something that’s very important to be developed,” Robb continued. “Maybe four or five entities would like to push that forward.
“That’s kind of the notion. It’s really not much more developed than that.”
OGE Energy reported third-quarter earnings on Thursday, beating analysts’ expectations with a net income of about $251 million ($1.25/share). That compared favorably with the year prior, when the company reported earnings of $205 million ($1.02/share).
Thomson Reuters had projected earnings of $1.11/share.
The Oklahoma City company said it benefited from more favorable weather, rate recovery and 9,000 new customers. OGE executives said they see “upward momentum” in the company’s historical load growth of 1%.
OG&E service trucks | OGE Energy
“There’s a lot of modeling that goes into forecasting load growth,” CEO Sean Trauschke told financial analysts. “To the extent we continue to see growth and we’re able to continue to attract customers and new businesses and have sales growth, that gives you the opportunity to spread costs over a larger base and minimize customer impact.”
Trauschke said OGE’s partnership in Enable Midstream Partners is in “good shape.” The midstream gas business contributed $37 million during the quarter to OGE, marking $1 billion in total distributions since the partnership with CenterPoint Energy was formed in 2013. Trauschke said the revenues are used to support dividend growth and invest in its Oklahoma Gas & Electric utility. (See related story, Hot Summer Yields Positive Earnings for CenterPoint.)
Natural gas midstream operations (Enable) | OGE Energy
The company revised its year-end earnings guidance to $2.24 to $2.30/share, up from $2.05 to $2.20/share.
CenterPoint Energy’s third-quarter earnings surged more than 57% thanks to record electricity usage this summer, the company reported Thursday. Profits were $241 million ($0.47/share) for the quarter, compared with $153 million ($0.35/share) a year earlier.
CenterPoint’s performance exceeded Zacks Investment Research’s projection of 43 cents/share.
The company’s Houston transmission and distribution utility reported operating income of $269 million for the quarter, up from $227 million in 2018’s third quarter.
“Our utilities delivered another strong performance this quarter, driven by solid customer growth, disciplined cost management and favorable weather,” CEO Scott Prochazka said.
CenterPoint Energy headquarters in Houston
The company also reported a $77 million distribution from Enable Midstream Partners, its gas gathering and processing partnership with OGE Energy. Enable is forecasting a distribution of $385 million to $445 million in 2020, bringing CenterPoint’s cash distribution since 2013 to $1.8 billion. (See related story, OGE Earnings Surge, Beat Expectations.)
Tempering the company’s positive news was a recent Texas administrative law judge’s proposed decision that a requested Houston electric rate increase of $154.6 million be reduced to $2.6 million, or 0.11% of its present rate base. The docket is on the Texas Public Utility Commission’s agenda for its meeting this Thursday (49421).
Prochazka told financial analysts during the earnings call that the decision was “clearly not a good outcome.”
“We’ve assumed we would at least be recovering the additional investment, the billion dollars plus that we have already put in service that are not yet in rates. If we recover just that piece, it would be an increase in rates,” he said. “The process isn’t over, and the commissioners haven’t yet opined on this. We hope the commissioners will have a different view of it.”
ATLANTA — NERC’s Board of Trustees last week accepted the EMP Task Force’s Strategic Recommendations report but pointedly did not endorse the panel’s suggestions, saying it will consider them after reviewing stakeholders’ comments.
The issue of electromagnetic pulses is a polarizing one, and at least some of the task force’s recommendations — notably calling for guaranteed cost recovery for investments to protect the grid — are hot potatoes for NERC. The draft Strategic Recommendations report, which was released for comment Aug. 30, also urged more access to classified information.
The report made 15 recommendations in four areas — research needs; vulnerability assessments; mitigation guidelines; and response and recovery — and suggested lead and support organizations for each, including NERC, the Department of Homeland Security and the Federal Emergency Management Agency. (See EMP Task Force Calls for Federal Funding.)
The trustees praised the task force for its research but gasped at the potential implications of its recommendations.
“Reading through that document — it puts things into context that are extraordinarily complex in a way such that you can begin to see how we might actually tackle this initiative,” Trustee Rob Manning said. “But the complexity is what scares me. The breadth of recommendations, the scope of those recommendations — it’s truly scary. So many people have to be involved. So much action has to be taken by so many different parties.”
Trustee Jan Schori said it was “very helpful” that the report suggests potential lead and support agencies for the recommendations — all 15 of which list NERC as lead or co-lead.
“I would be interested in input from those that comment on what role NERC should play going forward,” Schori said, noting “some of [the roles] are … not areas where we … have taken the lead.”
Schori also said she “can understand why the industry participants would be very concerned about … the question of cost recovery for work that is done” in response to any standard or guideline adopted by NERC.
“Traditionally, NERC is the technical resource. We don’t usually get into opining on cost recovery matters. And so … I’m very cautious about those parts of the report.”
A number of the industry comments pushed this theme, arguing that the task force’s recommendations gave NERC too prominent a role and often relegated more qualified bodies to a supporting function. For example, Ruida Shu, manager of reliability standards at the Northeast Power Coordinating Council, suggested that the Department of Energy should take the lead on providing educational materials relating to EMP preparedness, as “NERC is not equipped to engage in mass public educational endeavors.” In the same vein, representatives from Exelon and the Edison Electric Institute recommended that DHS replace NERC as the lead on coordination across utility sectors.
Taking questions about the task force’s perspective a step further, Robin Yee, adviser on U.S. affairs and grid security at the Canadian Electricity Association, objected to the U.S.-centric framing of the report and its lack of attention to the legal and regulatory requirements of other jurisdictions. Yee requested that “NERC develop a framework for ongoing consultation and dialogue between governments,” so that policies affecting the North American grid would take note of all relevant perspectives.
Kim Thomas of Duke Energy said the task force had failed to make use of “the full body of work already performed in the industry for this topic” and recommended NERC “acknowledge and utilize work-in-progress or completed for this topic [in order] to avoid duplication of work and to provide additional depth and understanding.”
No Confusion
“We don’t want any confusion on accepting the report as [representing] final approval of the recommendations,” said board Chair Roy Thilly, who promised the board would issue its recommendations on EMPs in February.
Thilly said the board will solicit additional comment from NERC management and others on the recommendations and what it should prioritize. “I suspect there are budget impacts and other resource impacts. So, we need to understand we can’t just approve the recommendations without knowing those factors. We do have work to do to get to February.”
The task force’s work was informed by a report released by the Electric Power Research Institute in April that concluded a high-altitude EMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. The report prompted a harsh critique by the Electromagnetic Defense Task Force. The group, which has ties to Maxwell Air Force Base, contends EPRI underestimated the risks and 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.” (See Critics: EPRI EMP Report Understates Risks.)
Next Steps
NERC Manager of Standards Development Soo Jin Kim, who presented the recommendations to the board, said the task force would like to begin Phase 2 of its work — more detailed analysis that would be forwarded to the newly created the Reliability and Security Technical Committee (RSTC). The RTSC would “develop detailed mitigation guidance and policy and procedures for how to update certain response and recovery plans,” Kim said.
“Only after the detailed work is done at the RSTC level — if it identified that there are enhancements or gaps in the standards, there [would] be an initiative for the EMP Task Force to kick off a standards development effort,” she said. “But that would only be if necessary, after the technical committee has first done its homework.”
In response to a question from Manning about proposed next steps, Kim said the task force identified as a “threshold question … that there needs to be progress in determining what’s an acceptable level of [bulk power system] performance during an EMP attack.”
She also noted that EPRI and several utilities are planning field trials of potential mitigation measures.
“Hopefully those field trials will be able to shed some light on certain mitigations and how available that technology will be to industry generally,” Kim said. “There’s also several research efforts going on right now with the National Labs. We have been reaching out to DOE and DHS also to try to share more information and to get more accurate information so industry can make those vulnerability assessments and accurately look at their systems.”
NERC’s EMP Task Force proposed 15 recommendations on research needs; vulnerability assessments; mitigation guidelines; and response and recovery. | NERC EMP Task Force
While some of the recommendations are outside the ERO’s authority, some are actionable by NERC and “will largely flow right into the RSTC next year as part of Phase 2,” she said. “We hope these recommendations will flow into the development of next steps for the industry to move forward in addressing EMP events.”
Not all industry participants were as positive about the momentum of the task force’s work: while Mark Gray, senior manager of transmission operations at EEI, described the report as a “good first step,” he said more research was needed to develop an effective response. Gray also recommended the removal from the report of language related to local distribution providers and other systems outside of NERC’s statutorily designated role.
Andy Dodge, director of FERC’s Office of Electric Reliability, asked whether the other agencies suggested as having roles have “bought into” the recommendations.
Kim said the task force followed President Trump’s March executive order in “highlighting some of the agencies that could be on point” and noted that the task force — formed in April — had a “very aggressive schedule” with the directive to provide recommendations to the board by November.
“Several of the entities that we did reach out to, and some of our contacts, stated that we probably would not be able to get some type of endorsement,” she said. “There has not been an official stance from any of the government agencies. Quite frankly, in that amount of time, I don’t think we could have received an official statement … that they would be willing to take on some of those recommendations.”
“Is NERC leadership going to follow up with these entities?” Dodge asked.
