NERC has hired Lyceum Leadership Consulting to find replacements for former CFO Scott Jones and General Counsel Charles “Charlie” Berardesco, who is retiring this month. (See NERC Seeking New CFO, Counsel in Apparent Shakeup.)
Lyceum will conduct the executive search and provide candidates to NERC CEO Jim Robb.
As part of its search, Lyceum posted an hourlong audio program describing NERC’s role and including Lyceum founder Thomas Linquist’s interview with Robb and Berardesco.
With the departures of Scott Jones and Charles Berardesco, NERC CEO Jim Robb will have replaced three of his top officials. NERC’s proposed 2020 business plan also reduces Robb’s direct reports to five from eight. | NERC
Lyceum said candidates to replace Berardesco should possess legal and regulatory experience; strategic orientation (“creative and capable of thinking broadly about business … viewed as a potential successor to the CEO”); skills in “collaboration and influencing”; a results orientation (“ability to anticipate and prevent problems”); team leadership and people development; and cultural sensitivity (“ability to work as part of a business with a strong and diverse culture”).
Lyceum expects to accept applications through Sept. 18 and submit a “longlist” of candidates on Sept. 20, with the shortlist determined Sept. 27. Interviews will be scheduled in late October and early November.
DES MOINES, Iowa — Nick Brown remembers clearly back to 1985, when, as a young planning engineer, he took a leap of faith and joined an Arkansas company called Southwest Power Pool as Employee No. 7.
Back then, SPP was a much smaller regional organization and had yet to be incorporated. The Nebraska utilities had not joined, the Integrated System hadn’t been integrated and operations in Arizona were unthinkable.
“I just jumped at [the opportunity],” Brown said. “A lot of people thought I was crazy for … joining an organization that was not even incorporated at the time. It didn’t exist.”
On Tuesday, Brown, 60, told SPP’s Board of Directors he will be retiring after almost four decades in the electric industry and 35 years with the RTO, 16 as its CEO. His retirement will become effective in April 2020, by which time SPP will be a reliability coordinator and offering market services to companies in the Western Interconnection. (See SPP on Track for WECC RC Certification.)
Brown was elected CEO in December 2003, replacing John Marschewski. Since then, he has overseen the organization’s recognition by FERC as an RTO and the implementation of balancing and wholesale day-ahead markets. He has also focused the company on expansion into the Dakotas and as far west as Wyoming and Montana. SPP has invested nearly $10 billion in transmission facilities, and its footprint now extends to 14 states.
When the RTO was finally incorporated as a nonprofit in 1994, Brown notarized the legal documents. It still represents an important event to him.
“It still amazes me that this organization existed for 53 years and didn’t legally become a company until we incorporated,” Brown told RTO Insider. “It’s amazing how far we’ve come since then.”
“I have great appreciation for Nick’s contributions to an incredible amount of the RTO’s success,” Southwestern Public Service President David Hudson said. “His many years of service are remarkable.”
“It’s impossible to think of SPP without thinking of Nick Brown,” board Chair Larry Altenbaumer said. “[SPP’s] culture of collaboration was shaped and nurtured under Nick’s leadership.”
Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy, has worked with Brown for 23 years and credited his vision, leadership and focus for SPP’s “great success.”
“He has helped foster the organization’s growth while meeting the needs of the members and focusing on end-use customers for those 35 years,” Wise said. “It was his desire to have an effective stakeholder-driven culture where all members who participate have a voice.
“SPP wouldn’t be here today at all in the way that it is without Nick Brown as a leader.”
Brown said his decision was a mutual one between him and his wife, Susan, and not driven by SPP’s recent mushrooming growth.
“I’ve been thinking about this for a long time. The timing was right,” he said. “There’s no right time. A lot of people have postulated that Nick’s going to wait for this or he’s going to wait for that. SPP will always be a work in progress. It didn’t make sense to me to wait any longer.”
He becomes the second RTO CEO to step down in the last two months. PJM’s Andy Ott retired in June. (See PJM CEO Andy Ott toRetire.)
Outside of serving on corporate boards, Brown said he doesn’t have much planned except to spend time with his four children and two grandchildren, all of whom live within 5 miles of his house.
Asked if he intended to travel, Brown said, “I’ve traveled almost every week for 35 years. I don’t view travel as one of my retirement passions.”
Altenbaumer said Brown will work with three board members to ensure a smooth transition for his successor. SPP has engaged management consulting firm Russell Reynolds to conduct a “comprehensive search” for Brown’s replacement.
Brown became a vice president and corporate secretary in 1998 before assuming the CEO’s role. He began his industry career with Southwestern Electric Power Co.
He holds physics and math degrees from Arkansas’ Ouachita Baptist University and an electrical engineering degree from Louisiana Tech University. A registered professional engineer, a master electrician and an instrument-rated pilot, Brown is a member of several engineering, technical and professional honor societies.
“I’ve never regretted [my decision] for a single day,” Brown told the board, Members Committee and other stakeholders. “It’s been a true pleasure over the years working with many of you around the table. April 1 is next year, so don’t get too excited. This organization runs through my veins; it just does.”
“While we have some very big shoes to fill, we have an organization with a future that is every bit as bright and exciting as it has been,” Altenbaumer said. Turning to Brown, he said, “My thanks to you for everything.”
Missouri regulators are wrapping up a probe into the self-commitment and self-scheduling of generation into wholesale energy markets, questioning whether the practice is good for customers.
Though the Missouri Public Service Commission might take steps to begin curbing the investor-owned utility practice of self-scheduling resources in MISO and SPP, regulators so far have not suggested any action, instead labeling the investigation opened last month as a simple fact-finding mission. The agency said it‘s currently examining whether the practice benefits or harms ratepayers.
The PSC also directed the state’s utilities to explain their approach to resource bidding and how they decide between self-scheduling and bidding into the market (EW-2019-0370).
Commission staff will file a report on their findings no later than Aug. 16.
Comments on the docket have so far fallen along predictable lines, with utilities defending self-commitments as necessary for the health of fossil-fueled resources and environmental nonprofits criticizing the practice as a means to keep uneconomic coal plants operating.
For Reliability
Ameren Missouri said while it self-commits several of its units in the MISO market at minimum output levels under the RTO’s must-run commitment mode, it does not self-schedule its units’ dispatch.
The utility explained it self-commits its coal fleet when those units will be expensive to restart, are being tested or to stave off forced outages or higher maintenance costs due to inefficient unit cycling. The company also pointed out its Callaway Nuclear Energy Center must remain online, so it designates the nuke as a must-run resource in MISO.
Ameren said MISO probably experiences more self-commitments than SPP due to it having more nuclear generation in its footprint.
Callaway Nuclear Energy Center | Fluor
Kansas City Power & Light similarly claimed its fossil units are only self-scheduled in SPP for “safety, reliability, economic and environmental compliance reasons.”
KCP&L said it must sometimes manage the number of thermal cycles for the sake of a plant’s longevity or run a steam-fired power plant to maintain reliability during cold weather.
“SPP’s market model isn’t always able to consider risks to KCP&L customers’ reliable power supply,” the utility said.
KCP&L said it also self-commits for compliance and post-outage testing, to keep wind generation economic and to commit units with startup times greater than 24 hours, something SPP doesn’t currently offer.
“The SPP market model does not currently do a good job committing large, baseload units with long lead times, large startup costs and long minimum run times,” KCP&L said.
In comments, Ameren Missouri raised a similar complaint with MISO’s day-ahead market algorithm, saying the limited, 24-hour advance economic evaluation is inadequate for making decisions on generation with long lead times that can also become worn out by cycling.
MISO — which has long kicked around the idea of implementing a multiday market — recently announced it will roll out a new and comprehensive multiday operating margin forecast — although it will not tie financial commitments to the new forecast. (See “MISO Eyeing 6-Day Margin Forecast” in MISO Market Subcommittee Briefs: July 11, 2019.)
Ameren Missouri said it strives to sell energy into the market only when it stands to benefit customers, but that it also must take unit longevity into account when making commitment decisions.
Wasteful?
Renewable energy advocates Advanced Power Alliance (APA) and Clean Grid Alliance (CGA) pointed to a spring Grid Strategies report that concluded self-scheduled resources should be brought into the organized markets. The report estimated self-scheduled coal plants caused excess fuel costs of at least $85 million in PJM and $127 million in MISO in 2017. The groups also cited 2018 Union of Concerned Scientists research that estimated coal generation self-scheduling in PJM, MISO, SPP and ERCOTplaces a $1 billion burden on ratepayers annually.
APA and CGA said self-scheduling and self-commitments muddy the intended transparency of RTO markets, adding self-scheduled generation is “often less responsive to market prices” and can increase prices passed on to consumers when other market generation is available at a lower cost.
“The issue before the commission in this case goes directly to the heart of market activity within MISO and SPP. The self-commitment and self-scheduling of generation can undermine the transparency created by these markets, as well as the overall goal of producing a reliable and economic generation commitment and dispatch that is good for consumers,” the groups said.
“It is no secret coal generators nationwide have struggled to remain economically competitive, which has a detrimental effect on ratepayers,” the Sierra Club commented. “Excessive and unwarranted self-generation by these same generators could compound the negative economic effects on ratepayers.”
The environmental group urged the PSC to compel utilities to provide the same, detailed reasons behind the instances of self-commitment and self-scheduling they provide to MISO and SPP.
The head of the standard drafting team considering modifications to NERC’s frequency response standard predicted generators will oppose a standard that mandates they provide the service.
Ethos Energy Group’s David Lemmons, chair of the team considering revisions to BAL-003-1.1 (Project 2017-01) said at least 60% of respondents to the group’s survey “said don’t do a generator requirement.”
“In the past, we’ve discussed issues that might be brought up related to the need for a governor requirement — one being: Performance is sufficient without it right now. Why are we trying to add more to it?” Lemmons said during a July 23 meeting.
The second objection has to do with transmission tariffs. Lemmons said a generation owner that is a load service provider recounted to him a conversation he had with his balancing authority.
“He said my BA came to me — he’s also my [transmission service provider] — and said my generator was not performing very well [in providing frequency response] and I have to improve. I said, ‘No I don’t. I’m paying for that [service] under … the tariff.”
Time frames involved in system frequency response. | Claudia Rahmann, Alfredo Castillo
Susan Morris, an electrical engineer in FERC’s Office of Electric Reliability, said she didn’t see the issue as an obstacle.
“The need for frequency response has been around for a long time. I wouldn’t worry about the tariff unless there is a direct conflict, and I don’t think there is. This is not a new need. I don’t see the correlation.”
“The generation owner’s paying for the service and he [says he] doesn’t need to provide it himself,” Lemmons persisted.
“Then that’s a problem there isn’t it? Maybe they need a requirement because [crafting a generator requirement] is the right thing to do for reliability,” Morris responded.
Lemmons asked NERC staff to provide an opinion on the issue “so that this team has it available for those comments when we receive them.”
FERC appears to have addressed the issue last year, when it ordered transmission providers to amend their pro forma generator interconnection agreements to require generators have governors or other equipment to respond automatically to frequency disturbances (Order 842, RM16-6).
In a subsequent rehearing order, the commission said its ruling did not imply existing generators are entitled to compensation for providing the service. FERC also rejected suggestions it had prohibited frequency response requirements on existing facilities, saying such a conclusion would be “inconsistent with the fundamental purpose” of ensuring reliability (RM16-6-001).
Consensus Reached
The existing BAL-003 standard requires balancing authorities or frequency response sharing groups, where applicable, to maintain interconnection frequency within predefined bounds.
Phase I of the BAL-003 project proposed changes to address inconsistencies in the calculations of interconnection frequency response obligations (IFRO).
Phase II of the BAL-003 project is considering potential changes to make IFRO calculations and associated allocations more reflective of current conditions, considering load response and the generation mix. The standard authorization request requires the team to ensure overperformance by one entity will not negatively impact the evaluation of performance by another and measurements of primary frequency response are considered in addition to those for secondary frequency response.
During a day-and-a-half of meetings last week, the standard drafting team reached consensus it does not want to impose a headroom requirement on generators, Lemmons said. The team considers that a decision the balancing authorities should make “based on economics or whatever process they use today.”
The team also decided to prohibit outer loop controls that defeat governors from responding, Lemmons said. Outer loop controls are used by generators that “don’t want their output to swing because of emissions issues [or because] the transmission tariff is telling the generator to be on schedule at all times,” he said.
The team also discussed changing the standard’s current requirement that FERC Form 1 data be used to monitor frequency response.
Lemmons said the team has discussed whether to recommend changing the current standard’s use of data from Frequency Response Survey (FRS) Form 1. The options being considered include an alternate data source or eliminating the data provision requirement.
We “don’t like the 1600 path,” Lemmons said, referring to the filing of a data request under section 1600 of the NERC Rules of Procedure. “We’re concerned a non-enforceable, non-push data gathering process may cause problems.”
Duke Energy’s Tom Pruitt urged the group to move forward in selecting one of the several proposals for modification of the standard.
“We’ve got some really sharp folks [on the team] but at the same time, we seem to just keep going around and around in circles, and I want to break the habit,” Pruitt said. “If you really want to get dramatic about it, call it an intervention.”
Not everyone is sold on NERC’s proposal to merge three technical committees into a single Reliability and Security Council (RSC).
The merger of the Planning, Operating and Critical Infrastructure Protection committees, announced in June, will reduce the committee membership from a combined 100-plus to 33 voting members and five non-voting members. (See Three NERC Committees Likely to Merge.)
The draft proposal by the Stakeholder Engagement Team (SET) is intended to improve efficiency in recognition of the increasing overlap among the committees’ work. NERC officials said the Member Representatives Committee (MRC) and the NERC board had received complaints that too much manpower was being spent in supporting the technical committees.
The new Reliability and Security Council will have 33 voting members and five non-voting members, a big reduction from the 100-plus members on the three committees it will replace. | NERC
NERC’s Stephen Crutchfield told the Resources Subcommittee during a briefing July 24 the new committee will use a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).
The RSC will include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and vice chair. The non-voting members will include the NERC secretary, two U.S. federal government representatives, one Canadian federal representative and one Canadian provincial member, “straight out of what the OC and PC do today,” Crutchfield said.
Members will be selected based on interconnection diversity, subject matter expertise and a mix of small and large entities, he said.
“It is my opinion this whole revision in this manner is going to reduce stakeholder participation,” said Gerry Beckerle, of Ameren. “It’s going to reduce the effectiveness and will reduce the [level] of expertise we have at this level … I think this is a near-sighted effort.”
Beckerle questioned how the new organization would affect participation by non-members. “There won’t be enough room anymore in the meeting [space] correct?”
“Well, I don’t know,” Crutchfield responded. “I’ve heard people say we could have up to 300 people at the first meeting of this thing, so plan accordingly.”
“The new NERC offices meeting space is going to be capable of handling that large of a group?” Beckerle asked.
“I don’t think so,” Crutchfield said.
“I thought one of the reasons [for the change] was so they could hold these meetings at the NERC offices,” Beckerle continued.
“This team has not discussed specifically about how the meetings are going to be run,” Crutchfield said.
He added initial plans to allow nonmembers to listen via WebEx have “been kind of panned. It could be logistically a nightmare.”
The new Reliability and Security Council will have 33 voting members and five non-voting members, a big reduction from the 100-plus members on the three committees it will replace. | NERC
The current schedule calls for seeking MRC endorsement on Aug. 14 and delivering a final proposal to the board Nov. 6.
Assuming board approval, nominations for the RSC would be opened in November with appointments in January or February and the first meeting in March.
Resources Subcommittee Chair Tom Pruitt, of Duke Energy, expressed concerns over the schedule. “It seems to be a pretty aggressive timeline, personally,” he said. “I’m not sure if you go this quickly you’re going to be able to work out all of the kinks and all of the details.”
Expertise Needed
Crutchfield said “the RISC is going to be more of a forward-looking group, whereas the Reliability and Security Council will be [implementing policy]. And they both report to the board [of trustees].”
He said the proposal to have 20 at-large members is recognition that combining the OC, PC and CIPC will require members with broader expertise. “Having that at-large [membership] allows you to find the right set of people who can cover all the aspects you’re looking for — the technical, the leadership, the project management kind of oversight people … Whereas with the sector-based [membership], you may have somebody who’s just completely operations-focused. So now you’ve got to find somebody else to fill that planning role or somebody else to fill that CIP role.”
Pruitt noted the proposed merger borrowed changes some of the regional entities, such as the Midwest Reliability Organization, have adopted.
But Beckerle said the regions’ committee structure is not applicable.
“Since NERC develops continent-wide policy, I think it makes sense we have a group such as the OC, PC and CIPC to provide detailed stakeholder technical direction to NERC,” Beckerle said. The regions “have a much different role in things than they used to back when there were quite a few regional standards, procedures and policies. I think trying to compare and duplicate what’s been successful at the region level is probably not fully appropriate at the NERC level.”
MRC Questions
The reorganization also was discussed at the MRC informational session July 19.
Mark Lauby, senior vice president and chief reliability officer, said he was not concerned about a loss of stakeholder engagement.
“Where the real work is going on is in the task forces, subcommittees and working groups … [The RSC] will enable us to make all three aspects — planning, operating and cyber — a focus and address those problems together as one chunk of work rather than fragmented. And I think it will create a lot more effective solutions,” Lauby said. “I don’t think we’re going to be losing that much when it comes to engagement at that project management level.”
Board of Trustees member Robert Manning praised the Stakeholder Engagement Team for its “innovation and creativity.”
“It’s sometimes challenging to move to a new structure when we know the structure we have is very effective,” he said. “I think you guys have tried to make sure we preserve the best of what we have and open the door to efficiencies going forward.”
He added: “The nominating process [for RSC members] is going to be very, very important.”
Board of Trustees Member David Goulding agreed. “It still seems to me there’s a fair bit of criteria work [that] needs to be done [on nominating RSC members], particularly if — being an optimist — we have a lot of people wanting to actually be members. … The criteria [are] going to be … interesting … to put together.”
Membership criteria will be defined in the participation model presented to the board in November.
A webinar on the proposal is set for Aug. 8. MRC members can provide feedback via the committee through Aug. 6. Industry comments to the board will be accepted through Aug. 15.
NERC’s Standards Committee approved the posting of proposed changes to its geomagnetic disturbances (GMDs) standard and authorized new initiatives on cyber system information access management and operator certifications during a brief meeting Wednesday.
Revised GMD Standard Set for Posting
The committee authorized the initial posting of proposed reliability standard TPL-007-4 and its implementation plan for a 45-day formal comment period. The ballot pool will be formed in the first 30 days, and initial ballots and nonbinding polls on the violation risk factors and violation severity levels will be held during the last 10 days.
The proposed revisions to TPL-007-3 (Project 2019-01) were made in response to FERC Order 851, which broadened the definition of GMDs, required grid operators to collect certain data and imposed deadlines for corrective actions (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)
FERC’s November order directed NERC to revise the standard to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans.
GMD storm in Fairbanks, Alaska, April 2011 | NASA
SAR Authorized on BES Cyber System Information Access Management
The committee accepted a standard authorization request (SAR) and appointed a standard drafting team for potential revisions regarding access to bulk electric system cyber system information (Project 2019-02).
The team will work to clarify the critical infrastructure protection (CIP) requirements on managing access and securing BES cyber system information (BCSI).
This project will consider revisions to CIP-004 and CIP-011 and will review BCSI definitions in the NERC Glossary of Terms. The SAR said the changes would increase “choice, greater flexibility, higher availability and reduced-cost options for entities to manage their BCSI.”
The project also will seek to clarify the protections expected when utilizing third-party solutions such as cloud services. (See Panelists Seek FERC OK to Move to Cloud.)
Move to a Single Operator Credential
The committee approved a SAR by the Personnel Certification and Governance Committee to implement its “One System Operator Certification credential” whitepaper to require all system operators hold the same certification (PER-003-2). The committee said the change from the current four credentials (Reliability Coordinator; Balancing and Interchange Operator; Transmission Operator; and Balancing, Interchange and Transmission Operator) will support reliability by ensuring all system operators have the same base knowledge. It would require 140 hours of continuing education hours and 30 hours each of standards and simulation training.
Request for Interpretation Rejected
The committee rejected Powerex’s request for interpretation (RFI) of INT-006-4 (Evaluation of Interchange Transactions). Powerex requested clarification on whether the time allotted in Attachment 1, Column B for the “Timing Requirements for all Interconnections except WECC” and “Timing Requirements for WECC” tables are mutually independent of other columns.
It also sought clarification on whether a balancing authority that is not the sink BA can be allocated additional time from other table columns and exceed the assessment time listed in Column B. Powerex also asked whether a transmission service provider can be allocated additional time from other columns and exceed the assessment time listed in Column B in either table.
NERC staff recommended rejecting the RFI, saying, “The meaning of the reliability standard is clear and evident by … the plain words that are written.
“The amount of the time specified in each column of the timing tables pertains to only the specific column. Each of the requirements referencing Column B of the tables (Requirements R1, R2, R3) provide that the required action shall take place ‘prior to the expiration of the time period defined in Attachment 1, Column B’ and makes no reference to additional time that may be allocated from other table columns.”
Standards Documents Retired
The committee approved the retirement of three reliability standards resource documents, as recommended by the Standards Committee Process Subcommittee:
SC Procedure – Approving a Field Test Associated with a Reliability Standard (dated March 10, 2008);
Guidelines for Interpretation Drafting Teams (Sept. 19, 2013); and
SC Procedure – Processing Requests for an Interpretation (Dec. 9, 2012).
Revisions to the Standard Processes Manual (Appendix 3A to the NERC Rules of Procedure) clarified the processes for approving field tests, processing requests for interpretations and activities for interpretation drafting teams. The changes were approved by FERC effective March 1.
INDIANAPOLIS — State regulators should establish standards to ensure the cybersecurity of distributed energy resources, experts said at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit last week.
More DERs means more consumers joining the grid — and “more credit card numbers, more identifying personal data” at risk, said Tobias Whitney, technical executive for the Electric Power Research Institute, during a July 23 panel.
To address cybersecurity risks, Whitney recommended those in the industry do more to understand vulnerabilities in the supply chain and train a “cross-functional” workforce fluent in IT, operational technology, devices and connectivity. He also suggested industry players maintain security metrics to understand what cybersecurity measures are working.
Colleen Glenn, control systems cybersecurity analyst for the Idaho National Laboratory, said current DER technology is designed for functionality and not cybersecurity.
“Cyber vulnerabilities and cyber threats are inextricably linked. You can’t have one without the other,” Glenn said.
She cited the steps of the Industrial Control System Cyber Kill Chain as a common progression of events when a bad actor hacks the grid: reconnaissance, weaponization, targeting, delivery, exploitation, installation, control and action.
Glenn said hackers often use open-source, Internet-based information to begin a cyberattack. She said a popular starting point is the search engine Shodan, which identifies control systems connected to the Internet.
Web-accessible platforms are common with DERs, Glenn said, adding that she once accessed a solar array and its micro inverters through a webpage — all without a single prompt for login credentials. Sometimes, equipment passwords are contained in public operating manuals, and wind turbines are even “daisy-chained” together so cyber access to one means access to all, she said.
“So often vendors are the ones that really control what is designed. … Unless there’s a widespread demand for this, cybersecurity is not a major concern because it’s expensive and requires research,” Glenn said.
Danish Saleem, DER cybersecurity standards lead for the National Renewable Energy Laboratory, said vendors and utilities will not develop a requirement to include cybersecurity controls on their own.
Instead, cybersecurity controls should be required in utilities’ request for proposals, Saleem said.
“[Utilities] say, ‘Yeah but we don’t need another thing in our system to manage,’” he said. “This has to come from regulatory bodies. You have to fine them.”
Beyond that, regulatory bodies should include basic cybersecurity standards in the approval process, Saleem said. Cybersecurity should be baked into utilities’ design-level work, including plans to periodically update the controls.
Saleem also said he’s looking for regulators’ input on the SunSpec/Sandia DER Cybersecurity Workgroup, which is examining how the IEEE 1547 DER interconnection standard can be revised to include more cybersecurity.
Glenn urged regulators to participate in cybersecurity conferences and stay abreast of cybersecurity topics. “I think one of the greatest things you can do is be a champion of cyber hygiene,” she said.
DER Forecasting Essentials
Later in the day, another panel discussed the need for improved DER forecasting.
Juliet Homer, senior energy research engineer for Pacific Northwest National Laboratory, said DERs traditionally relied on historical trends for forecasts, excluding predictive factors.
“Going forward, there’s a need to move beyond these into more advanced forecasting,” Homer said. She said forecasting could consider growth projections, DER cost decreases and carbon goals. She also said commissions might use the Bass Diffusion Model, which gives a starting point picture of market penetration based on the theory that early adopters of a new technology influence subsequent adopters.
“With the democratization of our grid, customers are more in control, and they can be sneaky,” joked DER expert Patrick McCoy, of the Sacramento Municipal Utility District.
McCoy said regulators need transparency into DER load data, but that data can be proprietary or veiled behind privacy agreements.
“You’ve got third parties now that control their own [DER] data. … It’s not just about utilities anymore. It’s third parties and customers that are part of the equation,” he warned.
McCoy said commissions should draw distinctions between “need-to-have” data versus “nice-to-have” data and go after necessary data first. He said regulators should pursue reports on resource planning, distribution planning, DER studies, cost trajectories and economic studies. He also said regulators should gain insights into utilities’ customer research.
“It’s a moving target,” McCoy admitted of DER forecasting. “There’s a lot of work to be done.”
INDIANAPOLIS — State regulators considered the impact of a prolonged blackout for about half the country during the National Association of Regulatory Utility Commissioners’ first-ever “black sky” exercise July 21.
The simulation, part of the 2019 Summer Policy Summit, focused on terrorist-originated electromagnetic pulses. John Heltzel, director of resilience planning for the Electric Infrastructure Security Council, said EMPs should not be dismissed as an obsolete Cold War-era threat. “There are real actors in the real world that are thinking of ways to disrupt us with EMP,” he said.
The EIS Council defines a black sky as a catastrophic event that severely disrupts critical infrastructure in multiple regions for a long period. Heltzel said other black sky causes are earthquakes, severe weather and geomagnetic disturbances. Heltzel said the earth is due for a powerful sun storm within the decade, with such storms able take down large regions of the electric grid.
Heltzel also pointed to the economic collapse of Venezuela as another blackout trigger. “They were back in the Stone Age. They were drawing buckets of water from streams to drink. No purification,” Heltzel warned.
He also cited the risks of climate change — whose urgency, he said, is not in question.
“I’m not going to debate something I feel is very obvious. … The fact is the number of natural disasters is increasing, that from a preparedness and resilience standpoint, we cannot afford to not take action. … We need to make these events survivable because they’re not going to change,” he said.
The exercise simulated an approximate six-month total blackout on the entire Eastern Interconnection in winter affecting about 100 million people. It featured videos of faux newscasts, boil water advisories, interviews with evacuees, casualty reports and chaotic Department of Homeland Security, Department of Defense and Federal Emergency Management Agency briefings. The players eventually learned the blackout was caused by an EMP attack from a ship in the Gulf of Mexico.
In the first hours of the event, New York City restaurants held “fire sales” to get rid of food before it spoiled.
The simulation touched on gridlocked expressways, first responder no-shows, water and gas shortages, hospital evacuations, sewage backups, riots, inoperable interstate fuel lines and burned out generators. It also imitated mass population migrations, makeshift shelter setups and aid convoys. Power restoration was scarce and spotty, mostly on the fringes of the affected area, with some power plants and transformers irrevocably damaged.
Heltzel said that as energy infrastructure becomes more interconnected, interdependencies are compounded, so the loss of one connected element “becomes rapidly, extremely difficult.”
In between video clips, Heltzel pointed out that most military bases aren’t equipped to be energy self-sufficient. He also noted that the one area that didn’t lose power during 2012’s Hurricane Sandy was microgrid-equipped Princeton University.
“Generators are a problem because everyone thinks they’re a panacea,” Heltzel said, noting that generators sent to Puerto Rico during Hurricane Maria in 2017 quickly ran out of fuel and became useless.
Puerto Rico Energy Bureau Associate Commissioner Lillian Mateo-Santos recounted paying her neighbor for use of his diesel-run generator in the weeks following the hurricane. She said she remembered people feeling overwhelmed by hopeless.
“Hopelessness erodes any effort from the government or aid organizations. … You’re stuck in that mode,” she said.
EIS Council staff at the conference called the hurricane a wake-up call.
Regulators in the audience said that during a blackout, a near-term goal should be to convince as many people as possible to shelter in place. Others said state agencies should set up mandatory attendance agreements with employees in advance.
Some regulators pointed out that a blackout could become a nuclear disaster as well, as cooling systems lacking power eventually fail.
Heltzel said his simulation and warnings aren’t cause for hopelessness. “We’re not the doom-and-gloom guys. We’re the optimists,” he said.
He urged regulators to develop emergency communication systems and action plans that include backup power systems in certain necessary areas and microgrid-equipped military bases. He also advised the installation of backup batteries for traffic lights on major evacuation routes.
Regulators should also call for emergency operating procedures from their utilities and create a prioritization of power needs so responders know where to direct generators and concentrate restoration efforts first, Heltzel said.
He also said only a handful of states have completed preparations under the Department of Homeland Security’s Power Outage Incident Annex, which advises federal responders on how to provide recovery for different localities within a state.
“Ask them if they’ve got a plan in place where every soldier and airman knows where to go,” Heltzel said, referring to National Guard leaders.
Tension among PJM sectors boiled over Thursday after members once again deferred a vote on proposed manual revisions that seek to clarify the intersection of regional and supplemental transmission planning.
It’s the fourth delay since LS Power returned to the Markets and Reliability Committee in April for endorsement of its proposed changes to Manual 14B that would stipulate PJM remove a supplemental project from its Regional Transmission Expansion Plan if regulators denied the proposal’s certificate of public convenience and necessity.
Some stakeholders said they just want to move forward — whether that’s through a vote on manual language or taking the dispute to FERC — while others suggested PJM and certain sectors were dragging their feet intentionally.
“The issues that remain are obviously the toughest,” said Sharon Segner, vice president of LS Power. “We are thinking through options such as declaratory motions [at FERC] and things in that light if we can’t reach consensus. We want to do everything we can in terms of working through the process.”
PJM Vice President of Transmission Planning Ken Seiler said Thursday that while staff “generally agree” that supplemental projects should not be converted to baseline RTEP projects, nor undermine the integrity of the competitive FERC Order 1000 process, there are still concerns about displacing supplementals and when to remove projects without unraveling the entire RTEP.
“What takes precedent? Baselines? Supplementals? Upgrades? What’s the timing on it; what does that look like; and how do we coordinate on it, and where does the cost allocation lie?” he said. “The difficulty in all of this is … we can come up with language to mitigate 90% of the issues, but there’s always the one-in-100,000 scenario that we couldn’t conceive of in this group.”
Supplemental projects — those PJM deems unnecessary for reliability, operational performance or economic efficiency — have tripled over the last 13 years, accounting for 62% of the submitted RTEP project costs since January 2017, according to an analysis from American Municipal Power. In 2018, AMP found, transmission owners added $5.7 billion in supplementals and just $1.5 million in baselines into the RTEP.
LS Power and other stakeholders argue PJM holds ultimate authority over supplemental projects and should approve manual language that clarifies when and how such projects get dropped from the RTEP, though RTO staff don’t see it that way — even going as far as rejecting stakeholder-endorsed revisions that would have stated as much back at the January MRC. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
PJM’s unprecedented move spawned a special session of the Planning Committee that began meeting in February to piece together language that would satisfy stakeholders concerned about transparency and the possibility of supplementals displacing more cost-efficient regional transmission upgrades.
Aaron Berner, PJM’s manager of transmission planning, said that while conversations over the last nine meetings have been “robust,” there’s still more consensus to be found — a delay that left some stakeholders exasperated.
“From my perspective, we need to come to closure,” said Ed Tatum, AMP’s vice president of transmission. “This has to be done in 30 days.”
Bob O’Connell, director of regulatory affairs for Panda Power Funds, urged fellow members to consider delaying a vote until a proposal is ready, noting that he wanted to do anything to get the issue off the MRC’s plate.
“I don’t think we need to have this on the agenda month after month if they are not ready,” he said.
‘Unusual Circumstance’
Stakeholders approved the delay in a sector-weighted vote of 4.34 to 0.66, but the conversation was far from over.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), later presented a first read of Operating Agreement language crafted by the D.C. Office of the People’s Counsel and the Public Power Association of New Jersey to prevent PJM from unilaterally shelving endorsed rule changes without any recourse for disgruntled members.
“If stakeholders approve manual language and PJM says we cannot implement language, this OA language comes into play,” he said. “We’d ask stakeholders to be able to go to FERC. This is an unusual circumstance.”
Poulos said the language follows PJM’s choice in January to reject manual language that would have stated supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.”
AMP, the author of the revision, cited the transparency principles in FERC Order 890, saying TOs should, to the extent available, disclose asset-specific condition assessments and the criteria and models supporting supplemental projects. LS Power’s language about removing supplementals was accepted as a friendly amendment to the proposal.
PJM, however, said such revisions were an “overreach of the RTEP” and inconsistent with FERC rulings. While special PC sessions have continued to work the LS Power amendment, AMP’s proposal remains “in limbo,” Poulos said Thursday.
“The ideal is that this is not even necessary because we’ve reached consensus on the manual changes,” the D.C. OPC’s Erik Heinle said. “That’s our preferred route.”
States’ Role
A second proposal from Poulos clarified states’ rights in the transmission planning process, noting that PJM should “wait to see” if the relevant state regulator has even considered the supplemental project, let alone approved it, before including it in RTEP modeling.
The presentation stirred up more frustration among stakeholders and PJM itself, which argued the proposed OA language was out of scope, incomplete and inappropriate for a first read at the MRC.
“I don’t want there to be any suggestion that this OA language is anything that PJM has worked on or approved or endorsed,” said Chris O’Hara, counsel for PJM. “There’s language about removing things from the base case. … There’s nothing in your language about how that’s done, the notice, the abandonment costs,” he said. “There are so many issues in your language … some of which should be in a problem statement and issue charge.”
Other sectors — including TOs, generators and load — argued they weren’t consulted on the proposal and worried about the “collateral damage” that may ensue because of it. Others said the conversation belonged in a lower committee — not a special session scheduled on short notice on Friday afternoons that few can attend regularly.
“I suspect I support the proposal in principle, but I’m always worried about making an exception to how we approach something,” said Marji Philips, director of RTO and federal services for Direct Energy. “I think it should have been discussed in a lower committee. My point is that you did not consult with all the stakeholders and that makes me very concerned.”
David “Scarp” Scarpignato of Calpine said generators “have a big interest” in the language, but none were involved in drafting it.
“At least Calpine is in favor of more competition in transmission, but we are against accidentally harming us if this is done,” he said.
Jason Barker, Exelon’s director of wholesale market development, agreed it’s “best practice” for such issues to undergo vetting through the lower committees “where the subject matter experts reside.”
“We would support such a motion for a more holistic discussion of the issues,” he said, noting that TOs weren’t involved in the proposal either. “This is something we would find a lot of tension with. It seems reasonable to step back and have a discussion about this at the Planning Committee.”
AMP’s Tatum pushed back against the suggestion that the language was out of scope or that sectors were shortchanged of involvement.
“Can we all please stop pretending that we haven’t been talking about this since January? There’s been nine special meetings,” he said. “This situation is such that PJM has not taken the role to develop the OA language. CAPS did. That’s it.”
Susan Bruce, representing the PJM Industrial Customer Coalition, said she agreed with much of what had been said, including that discussions at the special sessions have suffered from a lack of sector representation and quarreling over process versus substance.
“To Ed [Tatum]’s point, we’ve talked around this so much; further delays start disrespecting the legal process and we want to have more confidence in the transmission space than exists currently,” she said. “I feel like we need to do something differently to move the issue forward — to feel like we’ve done the right thing. But it can’t be something that takes a long time — that feels like customers are being prevented from bringing something up for a vote, which is where we are at.”
PJM’s Seiler agreed that “conceptually nothing is new” in the proposed OA language, but that “the devil is in the details.”
“Whenever we get into the wordsmithing, we get into new things,” he said. “A little bit more time to surgically work these issues would be helpful. Either we agree and move on and then take what we can’t agree on to FERC and call it a day.”
PJM will hold three additional special PC sessions before the MRC meeting in August.
Interim PJM CEO Susan J. Riley told the Markets and Reliability Committee last week that the Board of Managers remains committed to an overhaul of market design in the wake of the GreenHat Energy default, but she urged stakeholders to move forward on “badly needed” credit policy reforms.
“I’m in the process of retaining independent expert policy advisers,” she said. “We need to get that right. We can’t have another situation like we experienced earlier with GreenHat.”
Susan J. Riley, PJM | PJM
Riley took over for former CEO Andy Ott this month after he retired and expects it will take about four months to find his permanent replacement. In the meantime, Riley said she’s been meeting with stakeholders to better understand the shifting dynamics of members’ priorities and to “strengthen relationships.”
“Your needs are changing and they vary from state to state, sector to sector and company to company,” she said. “The pace of change is faster than what we’ve seen in the past.
“We are a service organization, and I certainly don’t have all the answers, but I look forward to working with you over the next few months to better understand what your needs are.”
Riley concluded her remarks by saying PJM has the “highest concentration of really smart, highly ethical, highly committed people that I’ve ever worked with, anywhere, and I don’t want to lose sight of that as we move forward in making necessary changes. I think you, as our members, are in very good hands here.”
Task Force Sunsets Postponed
Dave Anders, PJM’s director of stakeholder affairs, told the MRC he will postpone a vote on sunsetting both the Energy Price Formation Senior Task Force and the Energy Market Uplift Senior Task Force as staff review other dormant groups in need of closure.
“I think there are more groups out there we need to take a look at,” he said. “We haven’t been really very disciplined about sunsetting task forces.”
The uplift group formed in 2013 and completed its work in 2017 with changes to the Operating Agreement to restrict the locations for up-to-congestion trades, increment offers and decrement bids. (See “Stakeholders Endorse Third Phase of PJM’s Uplift Solution Despite Opposition,” PJM MRC/MC Briefs: June 22, 2017.)
PJM filed its price formation plan with FERC in March and awaits a ruling. Some stakeholders questioned the logic of sunsetting the related task force before receiving an order from FERC, to which Anders agreed. He said staff will return to the MRC with a more comprehensive list of task forces next month.
Manuals Endorsed
PJM stakeholders unanimously endorsed the following manual revisions:
B. Manual 13: Emergency Operations, to provide a single location for reporting operational restrictions that impact multiday operations planning, replacing multiple forms of reporting currently employed by members. The changes, which incorporate lessons learned from 2018/19 winter operations, are intended to improve operators’ situational awareness and communication regarding cross-sector interdependencies. The changes align with new Markets Gateway functionality for resource limitation reporting to be implemented on Aug. 1 and adds clarifications on which units may be placed in maximum emergency during emergency operations.
C. Manual 18: PJM Capacity Market, adding administrative updates, deleting outdated provisions and adding revisions to conform with FERC orders resulting from a periodic review.
D. Manual 21: Rules & Procedures for Determination of Generating Capability, to clarify capacity injection rights (CIR) evaluations and conform with Tariff changes. Adds more explicit explanations and some omitted testing criteria regarding CIR evaluations for combined cycle units. Reclassifies run-of-river hydro units with storage and dispatch capability.
E. Manual 28: Operating Agreement Accounting, resulting from the periodic review. Adds documentation of the process to be used if state estimator loss data are unavailable for calculating transmission loss deration factors. Deletes obsolete section on calculation of credits for quick-start reserves. Updates credit calculation for resources providing reactive services. Updates formula terms for consistency.
F. Manual 39: Nuclear Plant Interface Coordination, resulting from the periodic review with the Nuclear Generators Owners User Group. Adds language on coordination around remedial action and load shedding schemes. Adds language regarding the regulatory requirements of the deactivation and retirement process and to address the coordination between reliability coordinators.
