Page 1236 – RTO Insider

June 2, 2019February 12, 2025

Stakeholders Discuss NYISO Grid Study, LBMPc Change

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders on Thursday debated the content of a draft study on the impact of public policy on the New York grid and learned about the ISO’s proposed changes to its carbon price calculation.

The draft “Reliability and Market Considerations for a Grid in Transition” study comes after New York Gov. Andrew Cuomo in January nearly quadrupled the state’s offshore wind energy goal to 9 GW by 2035, while his proposed Green New Deal would mandate 100% clean power by 2040, increase renewable energy requirements from 50% to 70% by 2030, and require other clean energy benchmarks. (See New York Boosts Zero-carbon, Renewable Goals.)

“What we try to do in the report is to describe the challenges and fill in the gaps,” Mike DeSocio, the ISO’s senior manager for market design, told the Installed Capacity/Market Issues Working Group.

NYISO first presented an outline of the new study, which analyzes the projected Bulk Power System in 2030 and 2040, at the group’s April 15 meeting. (See NYISO Studies Grid Transformation, Fuel Security.)

| NYISO

“The ISO would be better off looking at what the market will be like in five years and not spend too much time preparing for 15 or 20 years down the road,” said Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers.

DeSocio agreed but said some of the needed investments are long-term.

“I think looking at 2030 and 2040 is important, at least to provide reality checks on what people are planning,” said Mark Younger of Hudson Energy Economics. “NYISO needs to go out to 2040 and assume all-renewable generation, then do a multiday analysis of very little wind or solar, which would provide you a good snapshot of what you need for backup if you rely upon fossil generation compared to what you would need if you relied upon storage as backup.”

Noting that the state recognizes a carbon-reduction imperative that the market does not, David Clarke, director of wholesale market policy for Power Supply Long Island, suggested that NYISO’s study consider how to optimize various as-bid resources and other alternatives to achieve the state’s targets. He noted that whether carbon pricing is ratified or not, “sequestration might be a better way to achieve the goals cost-effectively rather than other approaches, including carbon pricing.”

Andrew Antinori, senior director of the New York Power Authority’s Market Issues Group, asked whether it would be more efficient for the ISO to see whether or not a carbon charge will be implemented before expending resources studying different possible futures.

Howard Fromer, director of market policy for PSEG Power New York, asked whether the ISO has looked at using external resources to provide reserves.

“It seems the movement of resources across borders is going to become more important,” Fromer said. “I know we don’t currently have any projects to look at that, but it seems important to look at the whole seam issue and see how to access those resources.” (See NY Carbon Task Force Discusses Seams, ‘Leakage’.)

DeSocio agreed that external resources do fit into the picture.

“We’re probably going to need additional transmission, but it’s got to be strategic, and we’re probably going to need additional capacity, but it’s got to be strategic,” DeSocio said. “We need to get the energy prices right … that’s what it’s about here. … My bias is not to spend a lot of time on expanding new capacity products; that’s a pretty blunt instrument.”

The ISO’s timeline is to get an updated report out by the end of summer and add some quantitative analysis ahead of the Board of Directors’ strategic planning session in September, DeSocio said. By the end of June, the Analysis Group will provide preliminary analyses from a different study examining the market impacts of pricing carbon and will complete its report by the end of July, he said. (See More Details Divulged on New NYISO Carbon Pricing Study.)

Carbon Pricing: Calculating the LBMPc

After considering stakeholder feedback, NYISO has revised its proposed calculation of the carbon component in locational-based marginal prices (LBMPc), now subtracting a variable operations and maintenance (VOM) cost from the LBMP. The resulting value will then be divided by the estimated marginal fuel cost ($/MMBtu) plus the cost of emissions ($/MMBtu).

“Adding the cost of emissions was suggested by a few stakeholders last time to arrive at a more realistic heat rate,” said Ethan Avallone, the ISO’s technical specialist in energy market design who presented the analysis.

As discussed in previous meetings, NYISO will set the LBMPc to zero when the calculated LBMPc is less than zero and set the implied heat rate to zero when the calculated implied heat rate is below the minimum implied heat rate. (See Carbon Pricing Impact on Waste-to-Energy Examined.)

“We will use the LBMPc to allocate the carbon credit to [load-serving entities] and to prevent leakage and distortion of regional flows by charging imports and crediting exports the LBMPc, and also to provide market transparency,” Avallone said.

LBMPc calculation – fuel indices by region | NYISO

Internal generators are charged based on their actual emissions — not the LBMPc.

The implied heat rate produced by the calculation should be limited by a minimum and maximum to maintain an appropriate LBMPc, Avallone said. Absent a maximum value, the impact of shortage pricing on the LBMP could result in an inappropriately high implied heat rate; without a minimum, the impact of renewable generation on the LBMP could result in an inappropriately low heat rate.

The implied heat rate should be set to zero when less than the minimum limit and set to the maximum when above the maximum limit, Avallone said. A low implied heat rate indicates that zero-emission energy, which does not bid opportunity cost, is likely marginal.

NYISO would post minimum and maximum heat rates on its website and is considering stakeholder feedback to describe potential future revisions to eligibility criteria, he said.

In addition, the ISO will post the effective social cost of carbon (SCC), as determined by the state’s Public Service Commission.

The net SCC would be the gross SCC, established by the commission, minus the Regional Greenhouse Gas Initiative price.

Avallone also presented a summary of proposed Tariff changes to accommodate a carbon pricing regime, with new sections to describe carbon charges, payments and residual allocation.

NYISO is considering stakeholder feedback to describe potential future revisions to eligibility criteria and plans to review the proposed Tariff changes again at the June 11 ICAP/MIWG meeting, Avallone said. (See “Tariff Terms, Penalties,” NYISO Commissions New Social Cost of Carbon Study.)

Illustrative change in revenues, 1×1 gas combined-cycle, assuming new entry is needed | NYISO

Enhanced Fast-start Pricing

In response to a FERC order, NYISO is revising fast-start pricing to apply to all resources that can start up and synchronize to the grid in 30 minutes or less, have a minimum run time of one hour or less, and submit economic offers for evaluation.

The commission on April 18 ordered the ISO to revise its pricing logic to reflect the start-up costs of fast-start resources and relax the economic minimum operating limits of all fast-start resources by up to 100% to allow them to set prices (ER18-33). (See FERC Orders Fast-start Rules for PJM, NYISO.)

Under the proposed changes, “we use special pricing logic to better reflect the true cost of energy,” said Whitney Lesnicki, an ISO manager for energy market design, who presented the enhancements.

The ISO must submit its compliance filing by Dec. 31 and implement the changes by Dec. 31, 2020.

June 2, 2019

PJM MRC Briefs: May 30, 2019

VALLEY FORGE, Pa. — PJM on Thursday held what may have been its shortest Markets and Reliability Committee meeting ever, lasting just under an hour.

PJM’s Markets and Reliability Committee on May 30 | © *RTO Insider*

Annual FTR Changes

PJM presented a first read of its annual Manual 6 cover-to-cover review regarding financial transmission rights.

Brian Chmielewski, manager of market simulation, said staff are continuing their look into rule changes around FTR mark-to-auction credit requirements detailed in Section 6.7, but they’re moving ahead with default settlement rule updates, realignments to the OASIS refresh and the hourly cost component change, pending FERC approval.

Manuals Endorsed

Manual 01: Control Center and Data Exchange Requirements as a part of the cover-to-cover review.
Manual 03: Transmission Operations as a part of a cover-to-cover review.
Manual 07: PJM Protection Standards to update applicability references and an Institute of Electrical and Electronics Engineers standard reference.
Manual 11: Energy & Ancillary Services Market Operations and Manual 13: Emergency Operations to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
Manual 13: Emergency Operations as part of a cover-to-cover review.
Manual 36: System Restoration as a part of a cover-to-cover review.

— Christen Smith

May 31, 2019

CAISO Defers Day-ahead, SATA Initiatives

By Hudson Sangree and Robert Mullin

CAISO is postponing stakeholder initiatives on day-ahead market enhancements and storage-as-transmission assets (SATA), while adding four new initiatives as part of its 2019 annual plan.

The day-ahead market enhancements initiative has been postponed in response to stakeholder requests for more time to implement required changes, CAISO said in an update posted Wednesday. The effort aims to replace the day-ahead market’s current one-hour scheduling with a 15-minute granularity to improve handling of net load variability in real time. (See CAISO Says Changes Will Better Match Forecasting, Demand.)

“Grid infrastructure has advanced, the resource fleet has changed and the policies regulating operation of the grid have evolved (i.e., FERC mandated 15-minute scheduling in real-time energy markets). As a result, hourly scheduling granularity is no longer the most efficient way to schedule resources,” the ISO said in its straw proposal for the initiative.

As a byproduct of the initiative, CAISO is proposing to alter the Western Energy Imbalance Market to require participants to submit base schedules with a 15-minute granularity instead of the current one-hour.

“The use of hourly base schedules was originally chosen to align with the CAISO’s hourly day-ahead schedules, which were the reference point for imbalance energy,” the ISO said.

While EIM participants are generally supportive of the change, they’ve also cautioned CAISO that they need more time to comply with it.

In its April 1 comments on the ISO’s third straw proposal, for example, EIM member Arizona Public Service wrote that “while APS is supportive of moving to 15-minute scheduling and bidding granularity, these changes will require significant software and system changes, and will likely require modifications to EIM entities’ internal business processes. Sufficient time must be included in the implementation schedule for these system upgrades.”

NV Energy noted that the scheduling changes will require EIM members to revise their open access transmission tariffs (OATTs).

“NV Energy requests that the EIM entity OATT amendments be coordinated with the CAISO Tariff amendment for this market enhancement. It will be necessary for the CAISO Tariff to be approved with ample time for the EIM entities to file OATT amendment changes with FERC,” the utility said. It and founding EIM member PacifiCorp also urged CAISO to provide market participants 60 days to test the 15-minute functionality before implementation.

Northern California Power Agency (NCPA) also expressed concerns about the speed of the effort, contending the ISO “has exhibited a tendency to release major market changes that contain material deficiencies that have to be corrected over time.” Such an approach can have “financial consequences” for market participants, it warned.

“As such, NCPA believes the implementation timeline being considered will need to be adjusted to include very robust structured and unstructured market simulations, based on a clearly defined set of measurable and verifiable milestones, managed in close coordination and collaboration with stakeholders prior to releasing the changes into the production environments,” it said.

SATA Deferred

The storage initiative is being deferred until 2020 to provide time for the resolution of storage-dispatch policy in CAISO’s energy storage and distributed energy resources initiative phase 4 (ESDER 4). Phase 4 “will explore refinements to the distributed energy resource and storage participation models, as well as lower integration barriers for demand response resources,” the ISO said. (See CAISO Updates ESDER Phase 3 Proposal.)

“The scope of this initiative is to enable storage providing cost-based transmission services to also participate in ISO markets and receive market revenues to provide additional ratepayer benefits and provide greater flexibility to the grid,” CAISO wrote in its second revised straw proposal in October 2018.

New Additions

Meanwhile, CAISO said it’s adding four new measures to its 2019 roadmap:

Its new hybrid resources initiative will address issues related to solar-plus-storage in “forecasting, operations, resource adequacy and market design to provide for storage dispatch resolution in ESDER 4.”
A second initiative will address an “inefficiency” in the allocation of the real-time market neutrality settlement charge, which is currently calculated based on the sum of instructed and uninstructed imbalance energy, unaccounted for energy and greenhouse gas awards. The charge is allocated to settlements based on an offset calculated for each LMP component. The initiative proposes to eliminate the transfer of the real-time imbalance energy offset between EIM balancing authority areas, remove the GHG awards from the real-time market neutrality and create a GHG-specific neutrality allocation.
An intertie bid cost verification initiative will seek to align “intertie resource requirements with internal resources under FERC Order 831,” which directs ISOs and RTOs to cap resources’ incremental energy offers at the higher of $1,000/MWh or the resource’s verified cost-based incremental energy offer. FERC issued the order in November 2016 after wholesale power prices spiked during the winter storms of 2013/14 and generators said they could not recover their costs. (See CAISO Developing New Bidding Rules.)
A capacity procurement mechanism (CPM) initiative is meant to update the soft offer cap and consider 12-month pricing for CPM designations.

May 31, 2019

California Regulators OK Utility Wildfire Plans

By Hudson Sangree

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.

May 31, 2019

MTEP 19 Revealing High Price Tag

By Amanda Durish Cook

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.

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.

May 31, 2019

Out of the Game, Skelly Still High on Wind Energy

By Tom Kleckner

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.

“We thought transmission was going to be the linchpin of expanding wind energy,” Skelly said. (See Unfazed by Obstacles, Clean Line’s Skelly Focuses on Future.)

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.

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.”

May 30, 2019

NERC Seeking New CFO, Counsel in Apparent Shakeup

By Rich Heidorn Jr.

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.

Thilly and Robb declined requests for comment.

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.

May 30, 2019

New RCs Tell WECC Transition on Schedule

By Hudson Sangree

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.

WECC — 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 we b site 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.

May 29, 2019

PJM CEO Andy Ott to Retire

By Christen Smith

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 R i sks.)

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 Wo n ’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 F o rce.)

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 lette r 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.”

Leadership Shake-up

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.

May 29, 2019

UPDATED: Ohio Plan Subs Nuke, Fossil Fuel for Renewables

By Christen Smith

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.

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.”