The five members of the California Public Utilities Commission on Thursday unanimously approved wildfire mitigation plans filed by the state’s three large investor-owned utilities in response to last year’s Senate Bill 901.
But they warned that hardening the grid against fires and climate change could be an immense and extremely expensive undertaking.
CPUC President Michael Picker cited Pacific Gas and Electric’s plans to spend $237 million to expand its use of covered conductors along 150 miles of its overhead lines in 2019.
“Assuming that the 7,100 miles of PG&E’s system located in Tier 3 high-fire-threat areas is eventually covered, the magnitude of future general rate case costs could be enormous,” Picker said.
California’s investor-owned utilities have plans to de-energize transmission and distribution lines during high winds in areas of extreme (red) and elevated (yellow) fire risk. | CPUC
PG&E also intends to clear 305,000 hazardous trees near its lines at an estimated cost of $1.3 billion, he said.
The CPUC announced a series of public hearings Tuesday to consider PG&E’s request for a $2 billion rate hike over the next three years to cover wildfire prevention measures.
On Wednesday, a panel convened by Gov. Gavin Newsom — the Commission on Catastrophic Wildfire Cost and Recovery — issued a draft report and scheduled a June 7 hearing in Sacramento. Its recommendations include replacing the state’s strict liability standard for utilities when electrical equipment starts wildfires — called “inverse condemnation” — with a negligence standard. (See Calif. Must Limit Wildfire Liability, Governor Says.)
PG&E filed for bankruptcy in January, saying it faced at least $30 billion in liability for fires in 2017 and 2018, including the Camp Fire, the deadliest in state history. Southern California Edison also faces massive liability for its equipment’s role in starting the fatal Thomas Fire in 2017. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
On Thursday, the CPUC approved a proposed decision providing guidance on wildfire plans submitted under SB 901 along with individual decisions on each of the 2019 plans submitted.
In its plan, SCE said it will inspect 450,000 pieces of equipment by the height of the 2019 fire season, Picker said.
“It’s unclear how Southern California Edison can perform detailed inspections of this volume of equipment in so short a time,” he said. “But without better data and a stronger record, we’re not prepared to stop SCE from carrying out its new inspection program. It is required under SB 901 to prove the effectiveness of its inspection program.”
Picker said the commissioners want to make sure that SCE isn’t just doing drive-by inspections or duplicating routine inspections.
Both PG&E and SCE, the state’s first- and second-largest utilities, are playing catchup with smaller San Diego Gas & Electric, which has been hardening its grid and installing cameras and weather stations for a decade in response to catastrophic fires in 2003 and 2007.
While often cited as a model, SDG&E has far less territory to cover than PG&E or SCE, whose systems cover 70,000 and 50,000 square miles respectively. SDG&E’s service territory is 4,100 square miles. (See California Utilities Prepare, as Fire Season Looms.)
“In congratulating SDG&E, I don’t want to underestimate how long it’s going to take for the other utilities to get to that scale,” Commissioner Liane Randolph said. “I just want to make sure that we’re mindful of the heavy lift in terms of expense and time that it’s going to take to implement these plans, and as they get updated in the coming years.”
The CPUC also approved the wildfire mitigation plans of several smaller utilities in California: PacifiCorp, Liberty Utilities and Bear Valley Electric Service. The utilities’ lines run through high-fire-risk areas, commissioners said.
“It’s critical that these utilities have robust and effective mitigation plans as well,” Commissioner Clifford Rechtschaffen said.
Transmission owners NextEra Energy and Trans Bay Cable also had to file wildfire mitigation plans, which the commission approved.
Trans Bay operates a cable that runs under San Francisco Bay and said its cable was “fire-hardened by virtue of being located underwater,” Picker said.
In a separate item on utilities’ plans to de-energize lines in hazardous weather conditions, commissioners insisted that the tool be used only as last resort and not to avoid liability.
De-energization “presents its own safety and health risks,” especially to those who rely on electricity for medical equipment, Rechtschaffen said.
With about six months left before it seeks approval, MISO is polishing a draft 2019 Transmission Expansion Plan (MTEP) that could end up being one of the RTO’s most expensive buildout packages.
The draft so far contains 518 new projects at $4.3 billion to be recommended for approval. Included are 65 new projects valued at $771 million up for consideration in MISO South, stakeholders learned Wednesday at a subregional planning meeting.
MTEP 19 is so far clocking in at $1 billion more than the $3.3 billion, 442-project MTEP 18. (See MISO Board OKs Full MTEP 18 over Stakeholder Complaints.) MTEP 11, which contained the Multi-Value Project portfolio, holds the record for the most expensive proposal at $6.5 billion.
The highest-cost MTEP transmission projects in recent years have been in MISO South, which held five of the top 10 most expensive projects in MTEP 16 and MTEP 18, and eight of the top 10 costliest in MTEP 17.
MISO South Replacement Project
One of the priciest MISO South projects recommended in MTEP 19 will negate the need for two costlier projects approved for southern Louisiana the two previous years.
Cleco and Entergy’s proposed $81.5 million joint project near Lafayette can replace the North and East Acadiana Load Pocket (ALP) transmission projects that were set to cost a combined $213.1 million.
MISO engineer Patrick Jehring said the replacement Sellers LeBlanc project is poised to save customers $131.6 million, and the cost difference is the only “differentiating factor” between the projects. He said MISO supports the withdrawal of the ALP projects.
He praised Cleco and Entergy for working together on a lower-cost solution.
“This is really a good story to tell, and really only happened because of … significant collaboration between entities,” Jehring said. “The only way we got here is through engagement with Cleco, Entergy and the Lafayette Utilities System.”
The Sellers LeBlanc project involves a new 19-mile 138-kV line and a series reactor on an existing nearby 138-kV line for $66.7 million from Entergy. Cleco will take on the remaining $14.8 million by tying the new line into an existing 138-kV line and constructing a new autotransformer.
The project will resolve the overloading risk of multiple 138-kV lines around Lafayette. Additionally, MISO said there is approximately 300 MW of load in the Abbeville, La., area served by just one 230-kV line.
“It’s pretty obvious that we want to go with the cheaper project,” Jehring said. “We’ve truly identified the least-cost solution here.”
Jehring encouraged stakeholders to provide written feedback on the proposed project.
Issues in the Lafayette, La., area | MISO
Shortlist from MCPS
Meanwhile, MISO’s 2019 Market Congestion Planning Study (MCPS) has identified a short list of potential projects, with seven project candidates proposing to solve three separate issues making the first round of screening.
Three 345-kV projects ranging from $32 million to $85 million propose to solve congestion issues on the Helena-to-Scott County 345-kV line in southern Minnesota. MISO Economic Studies Engineer Karthik Munukutla said all three solutions are potentially eligible for market efficiency project categorization and cost sharing.
Two projects — a $58 million, 161-kV line rebuild and a $20 million new substation — are proposed to solve congestion on a 161-kV flowgate on the Iowa-Nebraska border. Finally, two new 115-kV lines at either $35 million or $37 million are competing to solve congestion on a 115-kV flowgate in southwest Arkansas. Munukutla said the four projects deal with MISO-SPP seams issues and will be added to the RTOs’ ongoing coordinated system plan study to see whether they’d make beneficial interregional projects.
Munukutla said he wanted to share preliminary MCPS results so stakeholders get an idea of which projects stand to provide the most value after initial transmission analyses. He said MISO expects to have more certainty in July about what projects may be selected from the study.
HOUSTON — It wasn’t too long ago that Michael Skelly was at the forefront of an effort to develop long-haul transmission lines to ship power from remote wind farms in SPP to urban centers to the east.
Skelly’s Clean Line Energy Partners, which he founded and led, was developing five projects capable of carrying 16.5 GW of energy. The future seemed bright.
He’s now on the outside looking in. Clean Line has sold off its projects, its employee count is down to zero, and Skelly has taken a senior adviser role for Lazard Asset Management.
Asked how he is doing during a panel discussion at the American Wind Energy Association’s WINDPOWER 2019 conference this month, Skelly responded, “I’m very happy.”
But Skelly exhibited new regrets over his failure to complete a long-haul, high-voltage project. He’s said Clean Line wasn’t able to “win the World Cup of transmission,” but that’s not to say someone else won’t.
“Hopefully, the second mouse gets the cheese in the transmission world,” he said, using the proposed $2.6 billion, 1.5-GW Cape Wind offshore site off Massachusetts as an example. Cape Wind was abandoned in 2017, but developers expect the nation’s 30 GW of offshore capacity to exceed 2 GW by 2030. Another 25 GW sits in the development pipeline.
“Transmission is super hard. We’re not really in the mood right now to do these giant projects in the United States,” Skelly said. “These things change. We’ll look back in 100 years. There’ll be times we didn’t do a lot of infrastructure; there are times we did a lot of infrastructure. Hopefully, the country will be in a better mood and ready to do these big-bone transmission projects.”
Coincidentally, Pattern Energy CEO Michael Garland sat at the other end of the panel. Pattern last year bought Clean Line’s interests in the Mesa Canyons Wind Farm and Western Spirit Clean Line projects in New Mexico. It has already reached a $285 million agreement with PNM Resources to sell Western Spirit once it’s completed in 2021.
“They’ve pushed forward with development,” Skelly said of Pattern. “Clearly it’s a new model, and that’s exciting.”
Clean Line sold another of its projects, the Grain Belt Express in the Upper Midwest, to Invenergy, contingent upon approval from Missouri regulators. The Public Service Commission has already approved the line after several earlier failed attempts and is now deliberating the sale.
Clean Line Energy Partners’ projects | Clean Line Energy Partners
The state’s most recent legislative session ended without eminent domain legislation, another positive for the $2.3 billion, 780-mile project that would connect Kansas’ bountiful wind energy with population centers on the other side of the Mississippi River.
“It’s survived several attempts to kill it,” Skelly said.
NextEra Energy Resources has acquired Clean Line’s Plains & Eastern Clean Line assets in Oklahoma. The Rock Island Clean Line was killed by Iowa legislation that made above-ground HVDC transmission projects illegal, Skelly has said.
Still, he remains optimistic about the wind energy business, pointing to decreasing costs and increased hunger for renewable energy.
“There’s a huge supply chain of service folks that really know how to do these things, and that will help us to be more flexible,” Skelly said. “There’s a bunch of states now that want 100% renewable energy. I think we’re on a great path, and for the younger folks just getting started in the industry, it’s going to be interesting.”
NERC is looking for a new CFO and general counsel, allowing CEO Jim Robb to reshape the organization’s senior management as he enters his second year on the job.
The Electric Reliability Organization announced on Tuesday that Scott Jones — its CFO, chief administrative officer and treasurer — had resigned and that General Counsel Charles “Charlie” Berardesco would be retiring in August.
There was no indication that Jones was on his way out earlier this month, when he gave several presentations at the quarterly meetings of the Board of Trustees and Member Representatives Committee in St. Louis. Berardesco also made no public mention of his retirement plans at the meetings. (See NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)
“I heard Scott was being forced out and they’re giving Charlie a retirement party,” one former senior NERC official who is still in contact with former colleagues said in an interview. “When you see two senior guys leaving at the same time, it’s clear somebody’s cleaning house.”
Berardesco, who joined NERC in 2012 from Constellation Energy, will retire on Aug. 31, NERC said. He served as acting CEO for about five months after the November 2017 resignation of former CEO Gerry Cauley following his arrest on domestic abuse charges in an incident involving his then-wife.
Robb joined NERC from the Western Electricity Coordinating Council in April 2018.
The former official said that Robb was selected by the board as “an independent guy who could come in and do what was necessary to take NERC into the future” after Cauley’s departure. “I’m sure he’s taken this last year to learn and evaluate any dysfunctions within the company.”
But Jean Cauley, Gerry Cauley’s ex-wife, said she suspects the moves may have been orchestrated by the board after Ken McIntyre, NERC’s vice president of standards and compliance, left the organization in March after less than three years.
Jean Cauley and the former NERC official said McIntyre was well regarded and was being groomed by Gerry Cauley as his successor.
“The board would have done a follow-up. They wanted to know why [McIntyre left]. If he told them, they would have started things rolling,” Jean Cauley said. McIntyre did not respond to a request for comment.
Jean Cauley said Berardesco and Jones had attempted to prevent her and staff from talking to board members about management problems at NERC after Gerry Cauley’s arrest for assaulting her.
She told police that her husband pushed her into a wall and a bathtub after she discovered him having cybersex with a “young female employee of his.” She suffered a broken spine in the assault and now needs a walker. Gerry Cauley resigned about a week after the incident. (See Cauley Resigns; NERC Launches Search for Replacement.)
“Scott was telling everybody I was unbalanced and a nut case and not to be believed,” Jean Cauley said in an interview.
“The board finally wised up and started seeing some of the deceit that’s been going on at NERC for years,” Jean Cauley said.
Cauley and several former NERC employees have described Berardesco as an abusive manager.
“Charlie is flat-out mean. He yells. Throws things,” she said.
“He was pretty rough on people,” the former executive said. “One of Charlie’s favorite things to say was, ‘I have more money than God.’ … If he liked you, you were fine. lf he didn’t like you, it was hell on wheels.”
NERC’s announcements gave no indication of any dissatisfaction with either Jones or Berardesco, neither of whom responded to RTO Insider’s requests for comment.
“Charlie has done an outstanding job during his tenure at NERC,” Board Chair Roy Thilly said in a statement. “He was instrumental in leading NERC as interim CEO during our time of transition.”
Jones, who joined NERC in December 2014 as senior director of finance, was promoted to vice president of finance in May 2016 and CFO in August 2017.
“During his tenure, Scott elevated the caliber of our financial processes and procedures and brought a high level of expertise to our accounting and budgeting processes that will benefit NERC and our many stakeholders well into the future,” Robb said in a statement.
NERC said Controller Andy Sharp will serve as interim CFO, responsible for oversight of business plans and budgets and day-to-day financial administration, while the organization searches for Jones’ successor.
With the latest moves, NERC will have replaced three of its top officials since Cauley’s departure. Senior Vice President and Chief Security Officer Marcus Sachs, then one of seven direct reports to CEO, was forced out in November 2017 and replaced by Bill Lawrence. (See NERC Parts Ways with Chief Security Officer.)
NERC’s proposed 2020 business plan also reduces Robb’s direct reports to five from eight. Two direct reports were reduced to one with Lawrence’s appointment. Michael Walker, a direct report as SVP/chief enterprise risk and strategic development officer, now is chief of staff for the E-ISAC. Also eliminated as a direct report was Tina Buzzard, the associate director to the office of the CEO, Cauley’s former administrative aide.
At its meeting in May, the board announced the appointment of two new vice presidents: Howard Gugel, director of engineering and standards, and Mechelle Thomas, chief compliance officer.
The key players in the Western reliability coordinator transition said Wednesday they’re largely on track to take over from Peak Reliability on a staggered timeline from July to December.
“Overall, our project is on schedule, and we’re making changes needed to be ready in August,” Bruce Rew, SPP’s vice president of operations, told the Western Electricity Coordinating Council’s RC Forum in a web-only meeting.
SPP and CAISO will be the main RCs for the Western states, while BC Hydro will assume responsibility for most of British Columbia. Gridforce will serve several small balancing areas in Arizona, Oregon and Washington. Alberta Electric Service Operator will continue performing the RC function in its province, rounding out the Western Interconnection.
Each entity provided an update on its progress Wednesday, and Peak described its gradual wind down as it exits the RC business this year.
CAISO and SPP are taking over RC responsibilties in most of the West this year. | CAISO
CAISO’s RC West will start the handoff when it takes over RC services for its California territory July 1. The ISO is awaiting final certification from NERC, which it expects to receive “any day now,” Tim Beach, RC West’s director of operations told the forum. (See RC West Moving Smoothly Toward July Handover.)
RC West staff members are in the second phase of shadowing Peak employees and have already been involved in problem situations, including a high-voltage event last weekend in California that required switching a transmission line out of service to mitigate the problem, Beach said.
After July 1, RC West will be preparing for Nov. 1, when it assumes the RC role for most of the West; 39 entities have contracted for its services from the Canadian border to northern Baja California and from the Pacific Ocean to the Rocky Mountains.
SPP has agreements with 13 customers, 11 of which have completed connecting with SPP, Rew said. The utility will start its certification process with WECC and NERC in August in anticipation of going live Dec. 3. (See SPP on Track for WECC RC Certification.)
Gridforce President C.J. Ingersoll said that as a relative newcomer, the company is in “catchup mode” but with its small footprint, things should work out fine.
“Our target go-live date is Dec. 3, and we feel like we’re on track there,” Ingersoll said.
Asher Steed, BC Hydro’s manager of provincial reliability coordination operations, said the company’s employees will start shadow operations with Peak on July 8 as it ramps up for its Sept. 2 start date.
Peak said all is going as planned on its end. Losing key staff members was a major concern earlier this year, but the company’s retention policies, including severance packages, appear to have worked, Chief Administrative Officer Rachel Sherrard said.
“We’ve had some unplanned attrition. Not a lot.” The company has shrunk from more than 160 employees in May 2018 to 119 today, she said.
Peak will start decertifying Dec. 4, vacate its offices in Vancouver, Wash., and Loveland, Colo., and cease to be a company by May 2020.
Eric Whitley, a grid expert from Folsom, Calif., who serves on WECC’s RC Transition Coordination Group, said “Peak will not be operational after the last transition on Dec. 3. There’s no going backwards,” he warned. Peak has posted a banner on its website showing the countdown to when it ceases operations.
The forums will continue every two or three months, as needed, Whitley said.
“It’s going to be a very active rest of the year,” he said.
FERC Chairman Neil Chatterjee’s suggestion that incentives may be needed to encourage investments in infrastructure security received mixed reaction in comments filed with the commission this week (AD19-12).
At a March 28 technical conference by FERC and the Department of Energy, Chatterjee said he wanted to learn whether incentives were needed to encourage security investments beyond those required by NERC reliability standards. (See TSA Defends Pipeline Security Practices Before FERC.)
In post-conference comments, the Edison Electric Institute and EEI members Dominion Energy, FirstEnergy and American Electric Power expressed support for some form of “resilience incentives,” along with the North American Generator Forum, Calpine and International Transmission Co. EEI asked for incentives for technologies such as “high-temperature superconductor, smart grid communications-enabled technology or resilient hardened substation designs.”
But EEI members Exelon and Alliant Energy opposed the idea, as did the Electric Power Supply Association, the American Public Power Association, transmission-dependent utilities (TDUs) and industrial consumers.
“An initiative to revise existing incentives or develop new ones may unintentionally distract resources from what is truly needed to continue making investments in the physical and cybersecurity of our assets: the regulatory certainty provided by timely and fair commission action on filings that involve cost recovery and price formation matters,” Exelon said.
[Editor’s Note: An earlier version of this article was based on only eight parties’ comments that were recorded in FERC’s e-Library before the agency shut down because of a failure of its HVAC system Tuesday.]
The North American Generator Forum said deregulated generators have no federal or state cost recovery mechanisms for security spending and “have significant challenges justifying additional cybersecurity spending beyond the mandatory requirements.”
Small generators also cannot afford dedicated information and operational technology staff on site, it said. “A government-sponsored program to provide cyber forensic assistance for facilities with limited resources would be a welcome tool for those facilities to be able to rely upon in times of need,” it said.
It also said market mechanisms and tax incentives should be considered as ways to provide cost recovery, noting state property taxes act as a disincentive for maintaining spare transformers. “We should ensure that early adopters that have completed security projects beyond the required compliance have a method to recover costs.”
EPSA called for “continued observation and analysis” of incentives in the future but said competitive suppliers “are currently able to recover costs associated with cyber and physical security through a number of sources, whether through market-based rates collected in the organized electricity markets, retail revenues, provisions within power purchase agreements or other sources of revenue.”
But EPSA member Calpine said the commission should consider “maturity credits” for industry participants who meet or exceed security goals to encourage best practices.
The Electricity Consumers Resource Council (ELCON), which represents industrial users, countered that competitive generators already have incentive to adopt cost-effective security practices — the opportunity cost of foregone market revenues if they are idled. “Shifting a segment of competitive generators’ costs to cost-of-service would set a deeply problematic precedent,” it said. “Security is an easy justification for cost-of-service entities to expand rate base.”
ELCON criticized ISO-NE’s proposal to recover generators’ costs for meeting critical infrastructure protection (CIP) standards via cost-based rates, saying such costs should be collected via energy and capacity markets. (See Eversource Balks at ISO-NE Plan on CIP Costs.)
“The costs of compliance with new regulations — CIP or otherwise — is an investment risk that should be internalized by competitive generators, not socialized through a new charge on transmission customers.”
If market power mitigation rules do not allow the collection of such costs, they should be changed, ELCON said.
Dominion, however, said generators subject to CIP standards in organized markets may be at a disadvantage without “tailored cost recovery mechanisms in RTOs.”
“Under current market rules, developers may favor only building new generation resources that are not subject to NERC CIP standards, resulting in incremental generation on the system that is not optimally located for reliability and system stability.”
Transmission Incentives
ITC said the commission should ensure cost recovery for transmission owners that go beyond NERC standards “consistent with Order No. 679 and associated commission policy.”
But Alliant rejected the idea of a “resilience incentive,” saying it would “provide a financial windfall to transmission owners without providing commensurate benefit to transmission customers. As stated at the technical conference, transmission owners currently do not have difficulty securing financing for transmission projects.”
“Given that utilities with cost-of-service rates are able to recover the costs of any prudent security investments, it is neither necessary nor appropriate to grant them financial incentives for such investments,” agreed the Transmission Access Policy Study Group, which represents TDUs.
APPA said “unjustified incentives could be particularly problematic for its” TDU members. “The costs of incentives paid by public power utilities in their transmission rates might be on top of infrastructure security costs incurred by public power utilities on their own systems,” it said.
FirstEnergy said FERC should ensure black start resources are “appropriately valued” as transmission assets. It also called for funding for information sharing programs such as the Cybersecurity Risk Information Sharing Program (CRISP) managed by NERC’s Electricity Information Sharing and Analysis Center. “The costs for participation in CRISP can be prohibitively expensive for smaller companies or municipalities. While companies participating in CRISP cover over 75% of U.S. customers, the goal should be 100%. Given the interconnected nature of the grid, the lack of participation by smaller entities could pose a significant threat to the reliability of the Bulk Power System.”
Gas: Incentives Yes, Standards No
The American Gas Association, which represents local distribution companies, said it supports tax credits to reduce the costs of cybersecurity investments and certification processes that can be used to obtain lower insurance rates.
It also said state regulators should provide cost recovery for physical and cybersecurity measures, including cyber mutual assistance programs, video surveillance, sensor technology, physical barriers and lighting. Only some states allow security riders to recover investments outside of a full rate case, AGA said.
It said the gas industry should continue following voluntary guidelines and best practices rather than being subject to the kind of mandatory standards that cover electric utilities.
“Allowing for riders based on, for example, the [Transportation Security Administration] Pipeline Security Guidelines, [the National Institute of Standards and Technology’s] Framework for Improving Critical Infrastructure Cybersecurity or [DOE’s Cybersecurity Capability Maturity Model] could accelerate the adoption of enhanced security practices and tools,” it said. “Cost recovery that is limited to mandatory guidelines or standards for high-risk or critical energy facilities penalizes forward-thinking operators that are being proactive voluntarily and looking ahead to the next challenge.”
Bandwidth
The Utilities Technology Council — a trade group for electric, gas and water utilities’ telecommunications and IT functions — called on FERC to join it in fighting the Federal Communications Commission’s proposal to allow others access to the 6-GHz frequency band, a communications channel used by electric utilities and other critical-infrastructure industries (CII).
“While UTC recognizes FERC has no authority over the FCC or spectrum, it nonetheless has a distinct interest in this proceeding. As the agency responsible for assuring the reliability of our nation’s Bulk Electric System, FERC should amplify the significant concerns raised by the entire electric utility and the oil and natural gas industries that are in opposition to the FCC’s 6-GHz plan and urge the FCC to protect utilities and other CII from interference in the band.”
Public Citizen criticized FERC’s reliance on “industry self-reporting” and said it should do more to protect whistleblowers. It also called for public identification of utilities that violate NERC standards and said NERC is not independent of the electric utility industry.
Delta Star, a Virginia-based provider of substation equipment, used its comments to make a sales pitch for trailer-mounted mobile substations, calling them “the only product that can be remotely secured from terrorist, cyber and physical threats and still be dispatched and installed within a matter of hours.”
Delta Star, a Virginia-based provider of substation equipment, said FERC should encourage the use of trailer-mounted mobile substations. | Delta Star
Beyond Standards
The National Association of Regulatory Utility Commissioners did not say whether it supported incentives. Instead, it suggested states would benefit from improved information sharing by FERC’s Office of Electricity and Infrastructure Security and DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
ELCON called for less emphasis on mandatory NERC standards and more information sharing on emerging threats and best practices for defense. “The rapid rate of change in computing technology is outpacing the ability of standards development processes,” it said.
On that, EEI appeared to agree. “The commission’s current approach of addressing new threats with new requirements is pushing the CIP standards into areas beyond the electric industry and electric company control,” it said. “We encourage the commission to take a more comprehensive approach to security than simply directing the development of modified or new industry security requirements.”
Andy Ott said Monday he will step down as PJM’s president and CEO next month, marking the second top executive to exit the organization this year.
Ott announced his retirement effective June 30 after more than two decades at the RTO, during which time he held several leadership positions, helped launch the wholesale energy market and navigated the fallout of the GreenHat Energy default — the latter of which he described as one of his greatest challenges.
“It has been a great privilege to serve as CEO and lead an incredibly talented group of professionals,” he said in a press release. “I am grateful to have worked with such a talented group of people throughout my career at PJM, and I know PJM will continue to move ahead with solid values and integrity.”
Ott will remain an adviser to the RTO’s Board of Managers through Dec. 31 to ensure a “smooth transition,” he said. Board member Susan J. Riley will serve as interim CEO beginning July 1.
After GreenHat
Ott said during his keynote address at PJM’s annual meeting last month that the ongoing fallout from the GreenHat default loomed large and that he is working hard to implement staffing and procedural changes recommended as part of an independent probe into the situation. (See ‘Naïve’ PJM Underestimated GreenHat Risks.)
Ott’s retirement comes two months after Suzanne Daugherty, the RTO’s longtime CFO, stepped down amid deepening criticism of the way PJM handled the default. Susan Buehler, PJM’s spokesperson, said the search for both positions remains “well underway,” despite Ott’s departure. She did not say the default contributed to his decision.
“He reached retirement age about a year ago,” she said. “I believe he thought this was the right time for him.”
At the Market Implementation Committee meeting on Feb. 6, Daugherty told members a FERC order to rerun the July 2018 FTR auction to liquidate GreenHat’s positions could add $250 million to $300 million to the $186 million the RTO had earlier projected the default would cost members. (See PJM Won’t Act on FTR Order Before Stay Ruling.)
The independent review released in March further blamed the RTO’s leadership for ignoring red flags about the company’s assets and exhortations from other members about the portfolio’s financial shortcomings — a failure of protocol Ott said “needs to change.”
“PJM needs to get better,” Ott previously told RTO Insider. “Quite frankly, we’re just not used to this type of behavior from a market participant.”
Stakeholders approved creation of a Financial Risk Senior Management Task Force in April to consider changes to PJM’s credit and risk management requirements, market rules, membership qualifications and the stakeholder process in response to the identified structural flaws in its financial transmission rights market. (See Stakeholders OK Risk Management Task Force.)
As recently as last week, however, some stakeholders felt PJM wasn’t doing everything it could to prevent the situation from happening again.
The Organization of PJM States Inc. (OPSI) said in a May 24 letter to the board that the RTO appears to have brushed off the probe’s recommendation to conduct a general market review “to evaluate the risks and rewards of potential structural reforms.”
“Neither the discussions in the Financial Risk Mitigation Senior Task Force nor PJM’s observations report indicates PJM is even considering such a general review, informed by expert help, of the FTR market,” said Michael Richard, OPSI president. “OPSI urges PJM to seize that opportunity, avail itself of outside expert help and conduct the general review of the FTR market recommended by the independent consultant report.”
Fresh Perspective
During Thursday’s Markets and Reliability Committee meeting, Ott said that both internal and external candidates will be considered for his replacement — though chatter among stakeholders suggests the latter is preferred.
“This is not a direction change; it’s just a CEO change,” Ott said. “We will stay true to our mission.”
Stakeholders expressed a desire for change and improvement — not continuity — especially when it comes to the cultural issues raised in the GreenHat report. PJM should find a leader with rock solid management skills that can be by supplemented a strong technical team who will guide the organization through the anticipated challenges of the next few years, members said. Others said it’s less important for PJM to ingratiate itself to the industry than it is to regain the confidence and trust of stakeholders.
Ed Tatum, vice president of transmission at American Municipal Power, wished Ott well and expressed appreciation for his hard work, describing the change in leadership as “significant.”
“PJM is very important to AMP, and we stand ready to work with the new leadership to navigate the many complex issues before us primarily through the stakeholder process, which has been and can continue to be the cornerstone to PJM’s success,” he said. “The PJM stakeholder process has worked well when there are incentives for all parties involved to collaborate to develop effective and balanced solutions. AMP looks forward to engaging in the process and to the insights and fresh perspectives that the new leadership team may bring.”
Ott’s departure came with a windfall of executive promotions for many of the RTO’s key leaders.
“We’re ensuring the structure of the company reinforces our commitment to reliable operations, fair and efficient wholesale markets and infrastructure planning,” Ott said. “Each of these promotions helps ensure we continue to be an electric industry leader in areas that are critical for our members, stakeholders and the 65 million people in the region served by PJM.”
Mike Bryson will now serve as senior vice president of operations, be a company officer and report to the CEO. Bryson has worked for PJM since 1998 and managed such duties as 24/7 transmission operations for real-time systems, scheduling, transmission and generation dispatch, reliability coordination, training, and engineering analysis.
Stu Bresler will take on the title of senior vice president of markets and planning. Meanwhile, PJM’s existing vice president of system planning, Steve Herling, will transition to the role of executive consultant, where he will focus on strategic system planning projects.
“A 29-year veteran of PJM, Steve has been integral in developing a robust system planning process aimed at delivering a strong, reliable, economical grid, and we look forward to his continued leadership and contributions as he transitions to this new role,” Ott said.
Ken Seiler will transition from executive director to senior vice president of planning, where he will 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.
Finally, Adam Keech will become the vice president of markets, where he will oversee all of PJM’s wholesale markets. Both Keech and Seiler will report to Bresler, PJM said.
A plan pending before the Ohio Senate could divert $300 million in ratepayer funds away from renewable resources to subsidize nuclear and fossil fuel plants, effectively gutting the state’s renewable portfolio standard.
The state House of Representatives on Wednesday voted 53-43 to pass House Bill 6, which would create the Ohio Clean Air Program. The legislation — supported by a monthly fee added to utility bills that would range from $1 for residential customers up to $2,500 for large-scale users consuming more than 45 million kWh per year — would replace existing charges for helping the state meet its standards for renewable generation, energy efficiency and peak demand reduction.
“The good news for electric customers is that for many, their bills will actually go down,” said Rep. Jamie Callender (R), chair of the House Public Utilities Committee and co-sponsor of the bill. “This is because there are already charges on their bills in the form of a renewal portfolio standard and energy efficiency standard/peak demand. The new program seeks to offer an alternative way to encourage cleaner energy production in Ohio.”
Electric companies currently assess a monthly $4.10 fee on customers related to green energy policies. The Ohio Environmental Council Action Fund says about 74 cents supports distributors meeting renewable resource standards and the remaining $3.36 is used for prioritizing energy efficiency and peak demand reduction.
HB 6 instead mandates residential customers pay $1/month, starting in 2021, for FirstEnergy Solutions’ Davis-Besse and Perry nuclear plants. The fee grows depending upon the ratepayers’ classification, with all revenues collected by the state treasury and distributed back to the defined “clean air resources” at a rate of $9/credit for every megawatt-hour of energy produced. Solar and wind generators are ineligible for the credit.
Perry Nuclear Power Plant
FirstEnergy said PJM’s existing market structure values cheaper, polluting fossil fuels over the reliable, carbon-free — and costly — generation from nuclear reactors. The plan levels the playing field, FirstEnergy said, given renewable resources like wind and solar already receive federal out-of-market subsidies.
“Wind can tail off during extreme cold temperatures, while solar is already offline in the evening or early morning hours,” said Dave Griffing, vice president of government affairs for FirstEnergy. “Nuclear power, by contrast, is remarkably reliable and typically picks up the slack as other generators struggle.”
The nuclear plants provide a combined 2,100 MW of capacity, enough to power 2 million homes, Griffing said. Without state intervention, the bankrupt company will retire both reactors over the next two years, taking $30 million in state and local tax revenue with it.
“Carbon and other harmful emissions will increase,” he said. “Grid resilience will deteriorate. And costs to consumers will go up.” The Union of Concerned Scientists said the bill will raise more than $170 million in ratepayer fees for the failing plants.
On top of the nuclear subsidy fee, which sunsets in 2026, electricity companies can recoup costs lost on long-term contracts to meet Ohio’s RPS mandates until 2030. American Electric Power, the Columbus-based utility that owns more than 40% of the state’s coal and natural gas plants, urged lawmakers to consider these existing contracts when moving the bill forward.
‘Total Flip-flop’
Supporters of the state’s RPS have unsurprisingly urged lawmakers to reject the bill.
“Ohio should not go down the path of effectively repealing this important policy and certainly not under the narrative it will provide cleaner air and better public health,” said Andrew Gohn, eastern region director of state affairs for the American Wind Energy Association, who noted funding from the state’s alternative energy mandates supports 2,200 MW of energy from wind farms.
The PJM Power Providers Group defended the RTO’s competitive markets for spurring renewable generation development and reducing carbon emissions 15% between 2013 and 2017. Sulfur dioxide and nitrogen oxide levels declined 65% and 31%, respectively, it said.
“This progress was not made because Ohio selected certain resources that it wanted to subsidize,” said Glen Thomas, the group’s president, “but rather through the setting of environmental goals and allowing the market, and consumers empowered with choice, to select which resources are best equipped to meet those goals.”
Ohio’s House Democrats sided with industry critics of the bill, instead proposing their own Clean Energy Jobs Act to preserve the state’s environmental goals. The caucus also criticized Republicans for using the bill to codify a state Supreme Court ruling that would allow the Ohio Valley Electric Corp. to charge customers up to $2.50/month to subsidize two of its coal plants — including one in Indiana.
“HB 6 is a total flip-flop that started by calling itself a clean air bill and evolved to be a corporate welfare bill that bails out a failing Indiana coal plant,” Assistant Minority Leader Kristin Boggs (D) said.
“It’s a bad deal that kills jobs, subsidizes failing out-of-state corporations and takes us backward,” Rep. David Leland (D) said. “We owe it to taxpayers to live up to our promise that we work for them. Our Ohio Clean Energy Jobs Act invests in a framework for the future that protects existing jobs, grows new ones and moves Ohio forward toward a clean energy economy.”
The bill, however, passed the House with support from 10 Democrats, while 17 Republicans voted against it. Republicans hold a comfortable 24-9 majority in the Senate, but it’s unclear how many support HB 6 in its current form. RTO Insider questioned Senate Majority Leader Matt Huffman about his caucus’ support for the bill and how quickly — if it all — it will be considered for a vote. He did not return requests for comment.
Republican Gov. Mike DeWine applauded House leadership for moving the bill quickly, in spite of the issue’s “difficult” and divisive nature, but didn’t commit to signing it should it cross his desk.
“As I have previously stated, Ohio needs to maintain carbon-free nuclear energy generation as part of our energy portfolio,” he said Wednesday. “In addition, these energy jobs are vital to Ohio’s economy. I look forward to this legislative discussion continuing in the Ohio Senate.”
Representatives from multiple sectors contend MISO should increase stakeholder representation on the committee that selects candidates for the RTO’s Board of Directors.
During a Tuesday conference call of the Board Qualification Task Team (BQTT), four of MISO’s 10 sectors expressed support for expanding stakeholder seats on the Nominating Committee, which is currently comprised of two stakeholder and three director seats. The team has six months to recommend any changes to improve the board selection process. (See TaskTeam Begins Look at MISO Board Rules.)
Task team chair Mark Volpe said a “common theme” among sectors is to both expand and rotate the sectors that serve on the Nominating Committee alongside sitting board members. However, the BQTT hasn’t made a formal recommendation to the board to expand the committee’s stakeholder seats.
Power Marketers sector representative David Bloom said his sector wants a more diverse set of stakeholders to make for a “more inclusive” Nominating Committee. The sector recommended MISO invite an Advisory Committee representative from each sector to serve on a voluntary basis. If that can’t be done, Bloom said the Power Marketers would like the Nominating Committee to add at least two additional seats for Advisory Committee members, provided the four members come from different sectors and eligibility is rotated each year among sectors.
Independent Power Producers sector representative Volpe proposed each sector representing a minimum of seven organizations be required to provide a representative to serve on the Nominating Committee each year.
If adopted, the change would leave MISO’s newest sector, the Competitive Transmission Developer sector and the Coordination Member sector — which contains only Manitoba Hydro — unrepresented.
“Expansion of the MISO Nominating Committee in this manner would be consistent with the majority of the committees representing the sectors as found in the other RTO/ISOs across the country,” the IPP sector said.
However, the Public Consumer sector proposed keeping the five-member format but flipping the structure so stakeholders hold the three-seat majority and board members are allotted two seats. Sector representative Jennifer Easler said the change could be adopted without modifying provisions to select Nominating Committee members.
“Currently, a majority of the five-member MISO Nominating Committee is held by MISO board members. Other RTO nominating committees are composed wholly of sector representatives or a majority of sector representatives,” the sector pointed out. The Public Consumer sector also recommended MISO rotate sector representation on the committee.
Transmission Dependent Utilities sector representative Megan Wisersky proposed the least intrusive “tweak,” calling for a rule forbidding any sector from having a Nominating Committee representative for two consecutive years. She said the rule would be in effect unless there’s a shortage of willing participants from MISO sectors.
Too Many Cooks?
The Environmental sector would also likely support a “broadening” of the Nominating Committee, sector representative Beth Soholt said. But she also asked if any other members foresaw an expanded committee becoming a “barrier” to consensus on candidates.
Former Nominating Committee member Wisersky said too large a group might make the interviewing process chaotic.
“It’s important to make sure the group is freshened periodically so different viewpoints are heard,” Wisersky said, adding that stakeholders serving on the Nominating Committee are there to represent the full membership, not the individual interests of their respective sectors.
Commissioner Mike Huebsch of the Public Service Commission of Wisconsin also cautioned against expanding the group too much, saying sector allegiance should be irrelevant on the Nominating Committee. He said if most sectors are allowed their own representative, sector representatives may start considering only their sector’s needs when selecting a MISO board candidate.
But Huebsch also said the manageability of a group often depends on the committee chair and personalities in the room. “I’ve been in groups of 25 that are of a manageable size and groups of three that are unmanageable,” Huebsch said.
The Nominating Committee is “a board committee, not a stakeholder committee,” Wisersky said, adding that she was personally undecided on whether stakeholders should outnumber board members on the committee.
Volpe reminded the task team that MISO is an outlier among all other RTOs in not allowing stakeholders to be a majority voice in the Nominating Committee.
The BQTT will next examine whether MISO’s one-year cooling-off period prior to service should continue being a prerequisite to serving on the board. The task team’s next meeting will be held in-person on June 19 in Traverse City, Mich., as part of MISO Board Week.
The task team is charged with producing a list of board qualification recommendations to be put before MISO’s Corporate Governance and Strategic Planning Committee of the Board of Directors by December.
NERC is looking for a new CFO and general counsel, allowing CEO Jim Robb to reshape the organization’s senior management as he enters his second year on the job.
The Electric Reliability Organization announced on Tuesday that Scott Jones — its CFO, chief administrative officer and treasurer — had resigned and that General Counsel Charles “Charlie” Berardesco would be retiring in August.
There was no indication that Jones was on his way out earlier this month, when he gave several presentations at the quarterly meetings of the Board of Trustees and Member Representatives Committee in St. Louis. Berardesco also made no public mention of his retirement plans at the meetings. (See NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)
“I heard Scott was being forced out and they’re giving Charlie a retirement party,” one former senior NERC official who is still in contact with former colleagues said in an interview. “When you see two senior guys leaving at the same time, it’s clear somebody’s cleaning house.”
Berardesco, who joined NERC in 2012 from Constellation Energy, will retire on Aug. 31, NERC said. He served as acting CEO for about five months after the November 2017 resignation of former CEO Gerry Cauley following his arrest on domestic abuse charges in an incident involving his then-wife.
Robb joined NERC from the Western Electricity Coordinating Council in April 2018.
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
The former official said that Robb was selected by the board as “an independent guy who could come in and do what was necessary to take NERC into the future” after Cauley’s departure. “I’m sure he’s taken this last year to learn and evaluate any dysfunctions within the company.”
But Jean Cauley, Gerry Cauley’s ex-wife, said she suspects the moves may have been orchestrated by the board after Ken McIntyre, NERC’s vice president of standards and compliance, left the organization in March after less than three years.
Jean Cauley and the former NERC official said McIntyre was well regarded and was being groomed by Gerry Cauley as his successor.
“The board would have done a follow-up. They wanted to know why [McIntyre left]. If he told them, they would have started things rolling,” Jean Cauley said. McIntyre did not respond to a request for comment.
Jean Cauley said Berardesco and Jones had attempted to prevent her and staff from talking to board members about management problems at NERC after Gerry Cauley’s arrest for assaulting her.
She told police that her husband pushed her into a wall and a bathtub after she discovered him having cybersex with a “young female employee of his.” She suffered a broken spine in the assault and now needs a walker. Gerry Cauley resigned about a week after the incident. (See Cauley Resigns; NERC Launches Search for Replacement.)
“Scott was telling everybody I was unbalanced and a nut case and not to be believed,” Jean Cauley said in an interview. She said she observed a culture in which extramarital affairs were covered up, “people were promoted based on who they slept with” and senior management ignored subordinates’ concerns.
“The board finally wised up and started seeing some of the deceit that’s been going on at NERC for years,” Jean Cauley said.
Cauley and several former NERC employees have described Berardesco as an abusive manager.
“Charlie is flat-out mean. He yells. Throws things,” she said.
“He was pretty rough on people,” the former executive said. “One of Charlie’s favorite things to say was, ‘I have more money than God.’ … If he liked you, you were fine. lf he didn’t like you, it was hell on wheels.”
NERC’s announcements gave no indication of any dissatisfaction with either Jones or Berardesco, neither of whom responded to RTO Insider’s requests for comment.
“Charlie has done an outstanding job during his tenure at NERC,” Board Chair Roy Thilly said in a statement. “He was instrumental in leading NERC as interim CEO during our time of transition.”
Jones, who joined NERC in December 2014 as senior director of finance, was promoted to vice president of finance in May 2016 and CFO in August 2017.
“During his tenure, Scott elevated the caliber of our financial processes and procedures and brought a high level of expertise to our accounting and budgeting processes that will benefit NERC and our many stakeholders well into the future,” Robb said in a statement.
NERC said Controller Andy Sharp will serve as interim CFO, responsible for oversight of business plans and budgets and day-to-day financial administration, while the organization searches for Jones’ successor.
With the latest moves, NERC will have replaced three of its top officials since Cauley’s departure. Senior Vice President and Chief Security Officer Marcus Sachs, then one of seven direct reports to CEO, was forced out in November 2017 and replaced by Bill Lawrence. (See NERC Parts Ways with Chief Security Officer.)
