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November 19, 2024

Con Ed: Failed Relay Protections Caused NYC Blackout

By Rich Heidorn Jr.

Consolidated Edison blamed a failed relay protection system for the blackout that darkened Broadway stages and left Manhattan residents without air conditioning, subways or elevators for up to five hours Saturday. About 72,000 customers were affected between West 30th and West 72nd streets, and from the Hudson River to Fifth Avenue.

The outage, which came on the 42nd anniversary of the city’s 1977 blackout, forced the cancellation of most Broadway shows, leading to impromptu performances outside theaters by cast members. Civilians took to the streets to direct traffic.

New York officials said about 2,800 stranded commuters had to be rescued from subways and hundreds more from more than 400 frozen elevators. Fans of singer Jennifer Lopez were evacuated from Madison Square Garden shortly her sold-out concert began. Temperatures were in the low 80s, with typical New York summer humidity.

The company said it restored power within five hours and that more than half the affected customers got power in less than three hours.

 

Con Ed
Radio City Music Hall was among the Manhattan landmarks forced to close after losing power. | ABC News

Source Identified

Con Ed said it had traced the outage to the failure of a relay protection system at its West 65th Street substation, which is designed to detect faults and cause circuit breakers to isolate and de-energize the faults.

“The relay protection system is designed with redundancies to provide high levels of reliability. In this case, primary and backup relay systems did not isolate a faulted 13,000-volt distribution cable at West 64th Street and West End Avenue,” Con Ed said in a statement. “The failure of the protective relay systems ultimately resulted in isolation of the fault at the West 49th Street transmission substation, and the subsequent loss of several electrical networks, starting at 6:47 p.m.”

Con Ed
Numerous subway lines were idled by the blackout. | Twitter

The company had initially said the 13-kV cable fault was unrelated to the outage. “While the cable fault was an initiating event, the customer outages were the result of the failure of the protective relay systems,” it said.

Consolidated Edison Company of New York (CECONY) President Timothy Cawley told The New York Times that at least two parts of the utility’s system failed to operate properly and prevent cascading to six neighborhood networks. He said he had never “experienced a case like this.”

Although it could take weeks before the company completes its investigation of the outage, he insisted he was “very confident” there would be no repeat.

But he said investigators had determined that the protective relay system there failed to operate as designed on two levels and those failures triggered the halt of the flow of electricity.

Reaction

The incident prompted howls of outrage.

The New York Post used the incident to call for the ouster of Mayor Bill de Blasio, a 2020 presidential candidate who was campaigning in Iowa when the lights went out.

U.S. Sen. Chuck Schumer (D-N.Y.) tweeted that the Department of Energy should investigate the outage with state and city officials. “This type of massive blackout is entirely preventable with the right investments in our grid,” he said.

Gov. Andrew Cuomo warned in interviews that Con Ed “does not have a franchise granted by God” and “can be replaced.”

“We got very lucky the other night. When you have a blackout in a city like New York, you are one step away from chaos and mayhem,” Cuomo said in a television interview. The 1977 blackout, which lasted more than a day, led to looting and arson that caused millions in damage. About 3,800 people were arrested.

Cuomo said the incident was just the latest in a series of failures, citing the outage following a fire in a Queens substation in December, a September 2017 power failure at a Brooklyn substation and an April 2017 subway outage blamed on the failure of Con Ed’s electric supply.

On Tuesday night, about 2,100 Con Ed customers lost power for up to seven hours after a fire at a substation on Staten Island.

Con Ed spokesman Michael Clendenin responded in a televised interview that the company’s system “is probably better than any other” in the U.S.

PA Consulting Group last year selected Con Ed as the Northeast region national winner of its ReliabilityOne Award for its 2017 performance.

Con Ed
Civilians directed cars through intersections after traffic lights lost power, including this “Star Wars fan,” who deployed a lightsaber. | Twitter

In January, CECONY, which serves New York City and Westchester County, asked the state Public Service Commission for a $485 million (8.6%) rate increase. Its sister company, Orange and Rockland Utilities, was among four companies penalized by state regulators last month for poor service. (See NY Utilities Dinged for 2018 Reliability, Safety.)

The fact that the incident occurred on the anniversary of the 1977 blackout led some — including “The Daily Show” host Trevor Noah — to speculate without evidence that sabotage might have been the cause.

NERC spokeswoman Kimberly Mielcarek rejected that idea.

“A root cause analysis of the outage is underway, but at this time, there is no evidence of suspicious activity or long-term impacts to infrastructure,” she said. “The bulk power system remained stable and unaffected by the outage.”

FERC spokeswoman Mary O’Driscoll said the commission “will be closely monitoring NERC’s steps in responding to this event.” New York PSC spokesman James Denn said state officials were investigating, “as directed by Gov. Cuomo.”

Although Con Ed officials said summer air conditioning loads were unrelated to the outage, they were making no promises about the system’s ability to withstand the coming weekend’s heat, when temperatures are expected to reach the upper 90s.

“We expect that there could be service outages,” Clendenin said. “Those things happen during heat waves.”

FERC Staff Hear Doubts on ISO-NE Fuel Security Plan

By Michael Kuser and Rich Heidorn Jr.

WASHINGTON — New England regulators and stakeholders told FERC on Monday they fear ISO-NE’s fuel security proposal could increase costs without solving the region’s winter supply concerns, urging the commission to postpone the RTO’s Oct. 15 filing deadline and require it to provide more analysis before drafting Tariff changes.

FERC staff heard testimony on the ISO-NE Fuel Security improvements
FERC staff heard state regulators and NEPOOL members weigh in on ISO-NE’s proposed winter energy security improvements Monday. | © RTO Insider

The “ISO, to its credit, has done a lot of hard work in a short amount of time,” Matthew Nelson, chairman of the Massachusetts Department of Public Utilities, told FERC staff during a daylong public meeting (EL18-182, et. al.). “But … this is a case of too much, too fast.”

ISO-NE
Matthew Nelson, Massachusetts DPU

“We don’t want to buy things we don’t need to buy,” said New Hampshire Public Utilities Commissioner Kathryn Bailey, who said the proposal could increase the region’s already high electric rates. “The current design suggests that we have a winter problem, but we’re going to pay for ancillary services year-round.”

Last July, FERC ordered ISO-NE to develop a long-term plan to address concerns over insufficient natural gas supplies for generation in winter. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.) In March, the commission pushed the original July 1 filing deadline back to Oct. 15.

ISO-NE
Kathryn Bailey, New Hampshire PUC

In April, the RTO, the New England States Committee on Electricity (NESCOE) and the New England Power Pool requested the public meeting with staff, saying that ex parte rules had prevented stakeholders from seeking guidance from the commission.

ISO-NE
Christopher Parent and Matthew White | © RTO Insider

ISO-NE Chief Economist Matthew White and Christopher Parent, director of market development, opened the meeting Monday with an overview of the RTO’s “energy security improvements” (ESI) proposal, which includes day-ahead energy option products, a multiday-ahead market (M-DAM) and seasonal forward markets.

White said the proposal’s energy option design — the only part of the proposal the RTO plans to file in October — solves the “misalignment” between the high price implicit in energy interruptions and the lower energy prices suppliers receive. The RTO gave its most recent outline of the proposal to NEPOOL members at last week’s Markets Committee meeting. (See related story, “ESI Conceptual Design,” NEPOOL Markets Committee Briefs: July 8-10, 2019.)

Seeking Delay

Regulators and NEPOOL members told FERC staff Monday that the RTO’s plan for a deterministic impact analysis was insufficient and should include probabilistic results. Some complained that the RTO had failed to adequately define the problem or had ignored how offshore wind, LNG tanker deliveries and energy efficiency could reduce winter concerns. And numerous witnesses said the RTO’s plan to submit a Tariff filing in mid-October is premature.

Jeff Bentz, NESCOE

Jeff Bentz, NESCOE’s director of analysis, said the schedule could be delayed by six months without impacting the proposed implementation.

“The ISO will not review its impact analysis until July 30. It will still be preliminary at the September 2019 Markets Committee vote, and a number of the modeling cases and specific assumptions are unclear at this point,” Bentz said. “With that backdrop though, ISO is encouraging state and stakeholder proposal amendments by mid-August, which is about two weeks after we get the impact analysis. … We have more questions than firm views at this point.”

NEPOOL Chair Nancy Chafetz, of Customized Energy Solutions, asked FERC to “keep an open mind” on the proposals. Although NEPOOL members have “jump ball” rights to propose an alternative to the RTO’s proposal, Chafetz said the stakeholder body won’t have an official position until it votes in October. And even then, she said, “some of our stakeholders may have difficulty in taking a position when we vote because of” the aspects of the plan that the RTO said it would have to deal with later.

Bentz and others also expressed concerns about the ability to mitigate market power. “We think it’s going to be hard to mitigate these call options. There’s a lot of subjective inputs in determining what your option bid is going to be,” he said.

What’s the Target?

Phil Bartlett, Maine PUC

Phil Bartlett, chairman of the Maine Public Utilities Commission, said the RTO’s “problem statement” is not specific enough because it fails to define the level of reliability it is seeking.

“We think this is a very aggressive time frame, so we would support any kind of delay to ensure there’s better analysis, to make sure that we have a fully developed solution and we know what the results are going to be,” he said. “If we end up … mostly just compensating existing generators for doing what they’re already doing, we’ll see significantly higher costs without much benefit. I think that’s a very real risk with this proposal.”

Liz Delaney, director of energy market policy for the Environmental Defense Fund, raised a similar concern. “While the ISO has made efforts to justify its targets and to tie them to NERC standards, it’s still unclear if this target is calibrated with enough precision to ensure that it’s procuring essential and not excessive quantities. ISO New England has not assessed whether a more modest procurement would still uphold the NERC standards.”

David Cavanaugh, vice president of regulatory and market affairs for Energy New England, said NEPOOL’s publicly owned utilities sector is not convinced the M-DAM is needed. “The M-DAM significantly complicates the design and implementation and would increase the cost of business for publicly owned entity members through increased IT requirements and staff with yet-to-be-determined benefits,” he said.

Katie Dykes, Connecticut DEEP

Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection, said regulators have been chastened by previous market overhauls touted as fixes, such as the Pay-for-Performance capacity market program.

She noted that the RTO is proposing not just three new ancillary services markets, but also the M-DAM and a new futures market. “With all of these new markets, we know that they will raise costs. The questions that we’re not prepared today to be able to address is whether they will solve the problem and whether they will solve the problem fully.”

Penalties or Incentives?

FERC Commissioner Richard Glick, who attended part of the hearing, also cited the incentives in the PfP program in expressing skepticism over the ESI plan. He questioned whether the RTO should be using a “carrot or stick” approach.

“There was an expectation that resources were going to firm up their fuel supply arrangements … and I understand that didn’t really occur,” Glick said. “Is this something we should be solving … with incentives or should we be providing penalties?”

“Whether it’s structured as an incentive or penalty, what it really comes down to in influencing the commercial decisions of entities … is the delta in their profit and loss if they take [action] or they don’t,” ISO-NE’s White responded. “I don’t look at it as there’s a fork in the road [where] you can create incentives or penalties. I think that’s not the most constructive way to approach it.”

Massachusetts DPU Chair Nelson said he worries “that a stick approach might spur on more [plant] retirements.”

But James Daly, vice president of energy supply for Eversource Energy, said prior markets mechanisms have failed to deliver needed infrastructure. “FERC should require ISO-NE to make fuel assurance mandatory and not an option,” he said.

OSW, LNG Ignored?

David Ismay, senior attorney for the Conservation Law Foundation, said the proposal underestimates the contribution of state-sponsored clean energy resources to winter reliability.

The “ISO confirmed that, had it been operating at the time, the 800 MW of offshore wind that will be brought online in the next few years for Massachusetts would have had significant energy security and cost benefits during a representative cold snap [such as] one that we experienced in the 2017-18 winter,” he said.

White said the RTO has done some modeling of prospective offshore wind. “The challenge, of course, is that it is prospective. There is only the one very small facility [operating currently],” he said, referring to the 30-MW Block Island Wind Farm. “It’s difficult to reliably simulate the potential variability when there isn’t enough data to go on.”

Richard Glick, FERC | © RTO Insider

Brett Kruse, vice president of market design for Calpine, said the RTO’s decision to sign Exelon’s Mystic generating plant to out-of-market contracts for Forward Capacity Auction 14 assumed there would be no LNG imports to the Northeast Gateway Deepwater Port Facility, which his company has used to supply its 2,000 MW of gas-fired generation in the region.

“We certainly believed that we could enter into similar agreements for the delivery years for FCA 13 and 14. In fact, we believe that many other alternatives (including additional oil backup) would have been available to ISO-NE at less than half the cost of the Mystic contract, if only ISO-NE would have opened their fuel security efforts to competition,” he said.

Other Proposals

Kruse and several other witnesses also offered alternatives to the RTO’s proposal.

Calpine proposed procuring fuel-secure megawatt-hours for the winter months three years in advance, a proposal it called the “forward enhanced reserves market.”

“We believe the forward market is the critical piece. Not the spot market,” Kruse said.

Neal Fitch, senior director of regulatory affairs for NRG Energy, said a seasonal forward market that incented purchases of oil and LNG four to six months ahead of real time would be most effective. But he said it will come with a cost. “Revenue-neutral solutions are really no solution at all,” he said.

ISO-NE’s Parent said the RTO will begin outlining its forward market proposal to stakeholders in August, but it won’t be included in its October filing. “Forward markets require sound spot markets. … to design a forward market in the absence of understanding how the spot market works is premature,” he said.

Tom Kaslow, vice president of market policy for FirstLight Power Resources, proposed the RTO limit the qualified capacity of gas-only resources in winter “to the level of such generation that the ISO-NE analysis indicates can be simultaneously fueled.”

“Qualifying a higher level doesn’t give you any more” capacity, he said.

States, Public Power Challenge FERC Storage Rule

By Christen Smith

State regulators, utilities and public power groups have asked the D.C. Circuit Court of Appeals to overturn part of FERC’s landmark rulemaking on energy storage participation, challenging the commission’s refusal to allow states to opt out.

The National Association of Regulatory Utility Commissioners’ (NARUC) petition seeks an order that portions of Order 841 and its rehearing order (841-A) “are arbitrary and capricious” and “not in accordance with law.” The Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association and American Municipal Power filed a separate petition Monday also challenging the orders.

In a press release Tuesday, NARUC said it hopes states and “relevant electric retail regulatory authorities” (RERRAs) will be permitted to manage electric storage resources (ESRs) in the same way they oversee demand response aggregation. NRECA told the House Energy and Commerce Committee in June FERC had overstepped its authority and local regulating authorities should be able to determine when and how ESRs join the marketplace.

storage
Energy storage in Minnesota | Connexus Energy

In May, FERC ruled 3-1 to reject requests it allow RERRAs the ability to opt out of its storage provisions, as the commission did for demand response under Order 719. Commissioner Bernard McNamee was the lone dissent. (See FERC Upholds Electric Storage Order.)

The majority said the Federal Power Act gives FERC clear jurisdiction over storage, citing the Supreme Court’s 2016 EPSA ruling. EPSA upheld FERC’s jurisdiction over the participation in RTO markets of DR resources, which are generally located on the distribution system. “The court did not find the commission’s authority to be lessened by the location of demand response resources behind the retail customer meter,” the commission said.

“We disagree with assertions by petitioners and the dissent that, unless the commission adopts an opt-out, the commission’s regulation of the RTO/ISO market participation of distribution-connected and behind-the-meter electric storage resources violates FPA Section 201. We find the Supreme Court’s jurisdictional findings in EPSA regarding wholesale demand response apply with at least as much force to participation in RTO/ISO markets by electric storage resources engaged in wholesale sales in interstate commerce, even where those resources are interconnected on a distribution system or located behind a retail meter.”

McNamee said the majority “fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”

“I believe Order Nos. 841 and 841-A are on solid footing when they deal with ESRs connected to the transmission system and how ESRs may participate in the wholesale market, and I concur in those aspects of today’s order. I am troubled, however, that the storage orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distribution systems and local retail customers,” McNamee wrote.

NARUC’s criticism echoes comments from RTOs, utilities and states who said FERC’s order exceeded the commission’s authority. (See States, Utilities, RTOs Push Back on Storage Order.) NARUC spokeswoman Regina Davis said the group’s petition won’t impact implementation of new rules because no stay was requested. There is no official timeline for court action, either, she said.

All six jurisdictional RTOs and ISOs are facing a December deadline for compliance with Order 841, which requires them to revise their market participation models to allow storage resources 100 kW and larger to provide capacity, energy and ancillary services within their technical ability. In April, the commission sought more information on the grid operators’ plans that were submitted five months prior. (See FERC Asks RTOs for more Details on Storage Rules.)

Supporters of FERC Order 841 said some of the submitted plans currently under review are impractical and burdensome.

Astrape Consulting released a study Monday — funded by the U.S. Energy Storage Association (ESA) and the National Resources Defense Council (NRDC) — that concluded PJM’s proposal requiring a storage asset to run for 10 continuous hours in order to qualify its full output for the capacity market “is unnecessary and unduly restrictive.”

“Energy storage is being installed on electric grids across the country at a rapid pace, helping transform our electric system to a more resilient, efficient, sustainable and affordable one,” said ESA CEO Kelly Speakes-Backman. “We stand behind the leadership at FERC to modernize energy rules to enable this transition. This study clearly affirms FERC’s judgement to include a broader set of technologies to participate, saving consumers money and supporting a diverse supply of clean energy generation.”

PJM spokesman Jeff Shields said Tuesday the RTO is awaiting FERC’s order on its Order 841 compliance filing. “Subject to FERC’s order, we are planning to implement in December 2019 as Order No. 841 proposed,” Shields said. “We will monitor any court developments in the meantime.”

FERC Chairman Neil Chatterjee last month described Order 841-A as one of the commission’s most important rulings it issued this year, calling it “one of the most significant federal actions we took to reduce carbon emissions.”

States, Regulators: Look Outside PJM for Next CEO

By Christen Smith

PJM’s state advocates and regulators want the organization to focus on external candidates as it continues the search for a new CEO — someone capable of prioritizing policy goals above “comity” with neighboring RTOs and ISOs.

Leaders from the Organization of PJM States Inc., the New Jersey Board of Public Utilities, the Consumer Advocates of the PJM States, and attorneys general from Delaware, Maryland and D.C. sent letters last week to the head of the RTO’s search committee, Board of Managers member Neil Smith, detailing what qualities former CEO Andy Ott’s replacement should possess. (See PJM CEO Andy Ott to Retire.)

PJM
Former PJM CEO Andy Ott | © RTO Insider

Ott announced his retirement effective June 30 after two decades with the RTO, during which time he 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.

Interim CEO Susan J. Riley said last week she expects to be around “about four months” while the search committee picks a new leader — and everyone, whether inside PJM or not, is on the table.

Some stakeholders hope it’s the latter of those two categories, however.

Aside from an economic and policy background and commitment to ushering in a cleaner power grid, CAPS President Kristin Munsch said the new CEO should want to work with states’ environmental goals — not against — and build a stronger partnership with the Independent Market Monitor.

“Just as PJM recognizes the rights of states to their policies, PJM must recognize the right of the IMM to be an independent body,” she said. “Arguments parsing Tariff language distract from the larger questions of how to use competitive markets to provide affordable and reliable electricity service.”

Acknowledging the necessity for PJM “to constructively work” across its seams on the “shared mission of reliability, New Jersey BPU President Joseph Fiordaliso also contended that “PJM management too often elevates a desire for comity with its sister ISOs and RTOs over representing the public interests of its own constituent states.

“This issue is particularly important to states like New Jersey, which sit directly on the seam between PJM and the New York Independent System Operator, and which have been responsible for fully one-third of all PJM transmission costs allocated over the past 15 years,” Fiordaliso said.

He said stymying climate change must be top of mind for PJM’s new leader as the RTO stands at the precipice of “tectonic shifts in their mission.”

Fiordaliso said an outside candidate could serve as a “fair and neutral arbitrator” among stakeholders, noting that leaders from other RTOs and ISOs should be avoided because “the management of those organizations have struggled to balance the oft conflicting views of state and federal regulators.”

“In a more tangible sense, we recommend that the search committee work to identify candidates capable of driving two (sometimes conflicting) policy agendas at the same time,” he said. “This experience will ensure PJM’s best-in-class management of today’s electric grid and vigorous planning for the needs of tomorrow’s electric grid.”

The attorneys general agree that supporting grid innovation that complements aggressive climate change policies adopted in some PJM states will be a key focus for the new CEO.

“PJM’s president should also have the economic and policy background to understand that state clean energy preferences are not out-of-market distortions to PJM interstate markets, but instead are important market corrections,” the officials said in their joint letters. “These policies address pressing environmental externalities and will modernize our state economies, creating jobs as well as environmental benefits.”

Smith instructed PJM members to submit all recommended candidates to the committee no later than July 19.

PJM PC/TEAC Briefs: July 11, 2019

VALLEY FORGE, Pa — PJM’s Merchant Transmission and Offshore Wind Task Force will soon bring potential rule changes for offshore wind development to the Planning Committee for consideration, RTO staff said Thursday.

John Reynolds, of PJM’s resource adequacy department, said stakeholders have so far offered three packages that address how transmission developers for single non-controllable AC lead lines could obtain capacity interconnection rights (CIRs) without committed generation.

The task force formed in February after the PC approved a problem statement and issue charge that would pave the way for existing and future offshore wind projects to develop throughout PJM, where researchers believe the potential is “big.” (See “PC Moves Forward on Offshore Interconnection Rights,” Big Prospects for Offshore Wind in PJM.)

Under existing rules, merchant transmission developers are only eligible to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. And because PJM does not offer CIRs to non-controllable AC lines, it is unable to perform stability or short-circuit analyses, as is typically done when a committed generation source exists.

Two of three packages introduce the concept of transferrable CIRs (xCIRs). In one plan, PJM would base the xCIRs on thermal studies only, while the second would allow requests for xCIRs based on all standard studies using a generic generator model. Both plans would make the rights transferrable to a generator project in the queue one year after the execution of the interconnection study agreement (ISA).

A third plan would modify the generator request to allow delayed submission of its data and use generic modeling instead for the feasibility and impact study. The official data would be due no later than 90 days into the study.

“These three are not the only ones we expect to have,” Reynolds said.

The task force has three more meetings scheduled before it returns to the PC for a first read of any draft language in September.

1st Read of Cost Containment Rules Coming in August

PJM
Mark Sims, PJM | © RTO Insider

Mark Sims, PJM’s manager of infrastructure coordination, told the PC that staff will present Manual M14F draft language for a first read in August, concluding months of educational updates and coordination with the Independent Market Monitor.

The language will detail PJM’s expanded cost containment process, which will include an updated hybrid fee structure. Sims previously told the PC that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)

Staff will seek endorsement of the language at the September PC and Markets and Reliability Committee meetings.

Unchanged Load Model Selection Endorsed

Stakeholders unanimously endorsed PJM’s load model selection for the 2019 reserve requirement study (RSS) after staff said it remained unchanged from the year before.

Patricio Rocha Garrido, of PJM’s resource adequacy department, said the load model of 2003-2012 remains the best choice for studying the 2023/24 delivery year. Analysis shows minor deviation in megawatt distance between 2018 and 2019, but Rocha Garrido described this as “insignificant enough” to not alter the model.

PJM also recommends switching its peak week to a different period in July so that it occurs in the same month as the “world” peak, but not on the same dates — which historical data suggests is unrealistic. The “world” load models include dates from the neighboring MISO, NYISO, TVA and VACAR regions.

Dominion, FirstEnergy Supplementals

FirstEnergy has identified protection schemes using a certain vintage of relays and communication equipment that have a history of maloperation on its Shawville-Shingletown 230-kV and Elko-Shawville 230-kV lines in the APS/Penelec transmission zone.

The 51-year-old Homer City North 345/230/23-kV transformer in western Pennsylvania faces increased probability of failure because of obsolete parts, leaks, deteriorated control cabinet components, high levels of heating gasses and moisture, and type “U” bushings. Likewise, the 34.5-mile Armstrong-Homer City 345-kV line is deteriorating from woodpecker damage, top and bayonet rot, and weatherization.

PJM
FirstEnergy has identified a special protection scheme for the 51-year-old Homer City North 345/230/23-kV transformer in Pennsylvania. | FirstEnergy

Dominion Energy wants to add a new delivery point for Mecklenburg Electric Cooperative in Boydton, Va., to support a new data center campus with a total load in excess of 100 MW. The requested in-service date is April 1, 2020.

The company said its Chickahominy 500/230-kV, 840-MVA transformer has been identified for replacement as part of its ongoing transformer health assessment process. Dominion said it’s the last known Westinghouse shell transformer — built in 1987 — on its system. These transformers are considered suspect because of previous transformer failures that reduced basic insulation level ratings and forced remanufacturing.

– Christen Smith

PJM MIC Briefs: July 10, 2019

VALLEY FORGE, Pa — Interim PJM CEO Susan J. Riley opened last week’s Market Implementation Committee meeting with an optimistic message about moving the organization forward after Andy Ott’s departure June 30.

PJM
PJM Interim CEO Susan J. Riley | © RTO Insider

“There’s a lot of work to do, particularly with our markets coming out of the whole FTR/GreenHat issue,” she said, referring to financial transmission rights trader GreenHat Energy’s default in June last year. “I’m here to assist with that and provide perspective to PJM. We’ve got to make these markets safe for participants.” (See Naive PJM Underestimated GreenHat Risks.)

Ott announced his retirement as CEO in May, marking the second top executive departure this year. (See PJM CEO Andy Ott to Retire and PJM CFO Retiring in Wake of GreenHat Default.)

Riley, a member of the Board of Managers, said she expects to serve as CEO for the next four months. She told the MIC that the organization is close to announcing the woman selected to be the RTO’s first chief risk officer, per the recommendation of the independent probe into how the GreenHat default unfolded.

“We are very excited to having her come on board,” she said. “There will be a lot more to come with ensuring the safety of our markets.”

5-Minute Dispatch and Pricing

Stakeholders unanimously endorsed a problem statement that criticizes the real-time security-constrained economic dispatch (RT SCED) and market pricing processes that PJM uses to send dispatch signals to generators and calculate LMPs.

PJM
PJM’s Market Implementation Committee met on July 10 at the Conference and Training Center in Valley Forge, Pa. | © RTO Insider

Siva Josyula of Monitoring Analytics last month said a price publishing delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.

The MIC will spend the next several months reviewing the issue and recommending necessary changes.

Order 841 Manual Revisions Endorsed

The MIC approved a slew of manual revisions related to FERC Order 841 on electric storage participation. The changes include updating Manual 11: Energy & Ancillary Services Market Operations; Manual 18: PJM Capacity Market; and Manual 15: Cost Development Guidelines to align PJM policies with those outlined by the commission.

PJM
Laura Walter, PJM | © RTO Insider

Laura Walter, senior lead economist for PJM’s advanced analytics and surveillance department, said Manuals 11 and 18 will clarify that storage resources can participate in the RTO’s markets and can dispatch and set price as seller and buyer. The revisions also note that stored megawatt-hours are billed at LMPs as wholesale.

In Manual 15, revisions detail business rules for cost offer development — specifically for hydroelectric resources and batteries and flywheels, PJM Senior Engineer Danielle Croop said. Staff also added definitions for efficiency factor, fuel cost, variable operations and maintenance (VOM) and ancillary service costs.

Efficiency factors measure the ratio of generation produced to the amount of electricity used to charge, Croop said. Fuel cost will use the average charging cost and will be defined in fuel-cost policies. Maintenance and operating cost inclusion and exclusion guidelines will be submitted in resources’ VOM templates, she said.

Modeling Units with Stability Limitations

The MIC is gearing up to discuss whether PJM should require generators to submit outage tickets during forced curtailments stemming from nearby transmission maintenance.

Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, presented a first read of the problem statement and issue charge he promised to bring during an Operating Committee meeting in May. His concerns arose out of proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations — possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)

O’Connell argues PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.

As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and it must be used in each of the markets. He also encouraged the RTO to publicize stability limits on OASIS prior to contacting the affected generator.

The MIC will be asked to endorse the problem statement at the August meeting and work on possible solutions during the committee’s meetings over the next few months.

Deadline Approaching for Gas Contingency Comments

PJM’s deadline for comments on its new Tariff language for gas pipeline contingencies comes and goes July 17 — but it appears many stakeholders remain unhappy with the latest draft.

On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664.) The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.)

Thomas DeVita, PJM’s senior counsel, said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.

PJM
Marji Philips, Direct Energy | © RTO Insider

Marji Philips, Direct Energy’s director of RTO and federal services, continues to believe the entire filing is fundamentally flawed and puts an unnecessary burden on load.

“If you want to have the right market response, you will look for other market incentives so that you’re not switching the cost of generation to load, because that’s what’s happening here,” she said. “The whole purpose of competitive markets is that the generator bears the risk, not load.”

She further argued that generators should be prepared to compensate during emergencies lasting 24 hours or more.

“If the conditions last longer than 24 hours, it’s no longer an emergency,” she said. “PJM shouldn’t be shifting the burden to load because the generator didn’t incorporate the risk into its CP offers. The generator guaranteed performance under CP, so it’s not load’s responsibility to cover the extra costs of that fuel.”

O’Connell agreed that mandatory operating instructions should only last for a set period of time, but he worried that memorializing such rules could encourage unsavory market behavior.

“One thing to address … the directive expires based on the rule, then 10 minutes later PJM issues the same directive,” he said. “Have we constructed a rule that can be worked around? Market participant perspective is that the market participant should be responsible for deciding what risks they care to take and what costs they care to incur, and if PJM overrides it, PJM should pick up the tab.”

It’s a sentiment Philips said she agrees with completely.

– Christen Smith

PJM Stakeholders Still Divided on Fuel-cost Policies

By Christen Smith

VALLEY FORGE, Pa. — Consensus on fuel-cost policies (FCPs) may elude PJM stakeholders as the Market Implementation Committee prepares for a vote on three divergent plans to restructure penalties and annual reviews.

The Independent Market Monitor and a collection of stakeholders want the RTO to ditch its yearly evaluation of unchanged FCPs and to consider extenuating circumstances when calculating fines for sellers who break those policies by failing “aggregate” market power tests.

PJM
Joel Romero Luna, Monitoring Analytics | © RTO Insider

“We are trying to go back to the way we did things before,” said Joel Romero Luna of Monitoring Analytics. “PJM or the IMM approved a fuel-cost policy and that remained in place until one of those parties or the participant said it was not good enough anymore.”

PJM argued that eliminating the annual review could allow ineffective policies to slip through the cracks, though it would consider a truncated analysis process as part of a compromise.

“We don’t want them [FCPs] to become stale,” said Glen Boyle, PJM’s manager of system operations analysis and compliance. “We want them reviewed once a year.”

When it comes to implementing an aggregate market power test, however, RTO staff said adopting such a process was “out of scope” of the MIC special session for retooling FCP rules.

PJM’s existing rules went into effect more than two years ago after months of contentious debate. In June 2017, the Monitor announced that it had rejected fewer than 5% of 479 FCPs during its annual review, accounting for roughly 11% of generating units. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.) Sellers without approved FCPs who offer into PJM’s markets currently face a penalty for doing so — though the Monitor proposes no longer allowing generators without an approved FCP to submit nonzero cost-based offers.

The Monitor wants to keep the current penalty factor when a unit fails the local/aggregate three-pivotal-supplier (TPS) test or submits an offer above $1,000/MWh. Romero Luna said the penalty should double when the unit either clears the day-ahead market or runs in real time on an incorrect cost-based offer and sets the marginal LMP, receives make-whole payments or offers above $1,000/MWh. Penalties would decrease to 10% when those two conditions don’t apply.

If a generator “self-identifies” the error and neither of the impact conditions apply, the penalty would drop 50%. If one or both of the situations occur, the penalty is reduced just 25%.

“We heard the current penalty didn’t have an incentive for people to self-identify errors that they made and that the penalties were too high,” Romero Luna said.

PJM
Adrien Ford, ODEC | © RTO Insider

Under the Monitor’s plan, a self-identifying generator with a 500-MW output and average real-time LMP of $40/MWh would see its existing $24,000 penalty reduced to as little as $1,200.

Adrien Ford of Old Dominion Electric Cooperative said a joint proposal from stakeholders shares a lot of similarities with the Monitor’s plan — except that self-identified errors reduce penalties to 25% and it creates a “safe harbor” policy for “unusual situations not contemplated by the FCP.”

“We followed the IMM framework while adjusting the value and adding a cap,” she said. More specifically, the joint stakeholder plan applies the current penalty factor if a unit clears the day-ahead market or runs in real time on cost-based offers and is paid a balancing operating reserve or the cost offer is above $1,000/MWh — or a unit fails the TPS test for constraints. If none of these conditions apply, the full penalty is reduced 90%.

The penalty calculation is assessed for each hour of the invalid offer and is capped at the calculated net energy margin for any impacted hour, Ford said.

The MIC will vote on the packages at its August meeting, just in time for the self-imposed Aug. 7 deadline set for the special session.

ERCOT Briefs: Week of July 8, 2019

ERCOT staff and stakeholders are preparing to bring a first set of real-time co-optimization (RTC) policy principles to the Technical Advisory Committee in a key test of their efforts to improve the Texas grid operator’s market design.

The Real-Time Co-Optimization Task Force, which is responsible for developing the RTC principles to align the ERCOT market with the direction given by the Public Utility Commission of Texas, will present five key principles to the TAC for approval during its July 24 meeting:

  • KP 1.4: System inputs into RTC
  • KP 1.5: Process for deploying ancillary services (AS)
  • KP 1.6: AS imbalance settlement with RTC
  • KP 3: Reliability unit commitment
  • KP 4: Supplemental AS market (SASM)

Stakeholders will debate KPs 1.5 and 3 and their alternative positions before the committee.

ERCOT
Matt Mereness, ERCOT | © RTO Insider

“The votes at the July TAC meeting will be a good indicator of whether the RTC Task Force’s efforts will be efficient in moving key design decisions through the stakeholder process,” said task force Chair Matt Mereness, ERCOT’s compliance director, following the group’s meeting Friday.

The task force is following guidelines set by PUC Chair DeAnn Walker for RTC, a market tool that procures both energy and AS every five minutes to find the most cost-effective solution for both requirements. (See ERCOT Real-time Co-optimization Falls into Place.)

Mereness said it was “helpful” to “have the PUC set direction on a number of key design issues.”

The RTCTF is also trying to engage other RTOs on lessons learned with their design and implementation of RTC. It hopes to bring MISO, PJM and SPP to Texas for a meeting in September.

ERCOT Comes Close to June Demand Record

ERCOT
ERCOT’s system met near-record demand in June. | NextEra Energy Resources

The ERCOT system came about 1.5% shy of setting a new demand record for the month of June when it recorded a peak of 68.1 GW on June 19, compared to the all-time record set last year at 69.1 GW.

June’s peak set a high for the year that has since been broken in July. The system twice surpassed 70 GW on Wednesday, registering a peak demand of 70.5 GW for the hour ending at 5 p.m.

ERCOT is expecting a record peak demand this summer of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. The grid operator has 78.9 GW of available capacity.

— Tom Kleckner

FERC Proposes $6.8M Fine for CAISO Market Manipulation

By Hudson Sangree

FERC on Wednesday ordered energy firm Vitol and one of its senior traders to show cause why they should not be fined for manipulating CAISO’s market to limit losses on the company’s congestion revenue rights (IN14-4).

The trader, Federico Corteggiano, had helped create software for CAISO’s CRR market and had engaged in similar market manipulation before while at Deutsche Bank, FERC’s Office of Enforcement said.

In the more recent instance, he sold power at a loss of about $4,500 to save Vitol more than $1.2 million on its CRRs, FERC’s enforcement staff alleged.

In its ruling, FERC proposed ordering Vitol to return the savings, with interest, and fining it $6 million. The commission proposed fining Corteggiano $800,000. The commission gave Vitol and Corteggiano 30 days to respond.

Vitol and Corteggiano disputed FERC’s findings in testimony and prior filings, saying the trades were intended to take advantage of high prices, not to benefit Vitol’s CRRs. FERC found the arguments unpersuasive.

In their report, FERC enforcement staff said that during five days in the fall of 2013, Vitol “sold one product — electric power — at a financial loss in CAISO’s day-ahead market to benefit its separate financial product — respondents’ congestion revenue rights. Corteggiano, co-head of Vitol’s financial transmission rights trading operation, was the architect of this scheme.”

In 2013, Corteggiano purchased CRRs through CAISO’s auction for the Cragview node, the point where CAISO transfers power from the PacifiCorp-West balancing authority area in far Northern California.

The LMP at Cragview reflects 100% of the congestion on the Cascade intertie, the FERC report noted. “Vitol’s CRRs would earn money from import congestion on the Cascade intertie and lose money from export congestion,” it said.

In mid-October 2013, CAISO partially derated the Cascade intertie — limiting exports while still allowing imports during portions of late October, November and December. In October, Cragview’s LMP hit an unusual high of more than $388/MWh. Export congestion accounted for about $350/MWh of that price, FERC said.

Vitol’s export CRRs would lose money every hour. The firm was able to buy counter-flow CRRs for November and December, mitigating its losses and flattening its position, FERC said. “However, because the monthly CRR auction for October had closed, it was too late to flatten Vitol’s CRR position for the last week of October.”

Corteggiano, who holds a Ph.D. in power system engineering, found a way to get around that problem — one he’d used before, FERC staff alleged.

“Corteggiano knew that he could likely eliminate the problematic export congestion for that week by importing physical power in the day-ahead market at Cragview. Working with other Vitol employees, Corteggiano arranged to buy [5 MW of] physical power in the Pacific Northwest and successfully offered it for import at Cragview. Vitol’s imports over the Cascade intertie achieved their intended purpose, preventing export congestion from occurring during the period of Vitol’s imports. …

“Respondents lost money on the imports, but by making them, [they] were able to eliminate the export congestion and thereby avoid the far larger financial losses they otherwise would have incurred on the CRRs at Cragview.”

‘Phantom Congestion’

While at Deutsche Bank, Corteggiano had figured out how to manipulate congestion costs at another partially derated intertie linking CAISO to northern Nevada, FERC staff said. He had bought CRRs that profited Deutsche Bank when there was export congestion on the Silver Peak intertie but lost money when there was import congestion.

“In January 2010, CAISO partially derated the Silver Peak intertie to 0 MW in the import direction and 13 MW in the export direction. Import congestion appeared on the intertie, and Corteggiano’s CRRs began to lose money. Corteggiano found that he could substantially alter or eliminate what he called ‘phantom congestion’ by trading small quantities of physical power in the opposite direction of the derate,” FERC enforcement staff said.

“Corteggiano testified that ‘phantom congestion’ is ‘congestion that is not triggered by market behavior or by physical flows in the system,’” the report said. “‘Phantom congestion’ is Corteggiano’s own description of a pricing outcome rather than an industry-recognized term.

“Corteggiano admitted to Enforcement in 2010 that he made unprofitable physical trades on behalf of Deutsche Bank to benefit CRR positions that otherwise would have been harmed by the congestion associated with partial derates at Silver Peak. This was the only time in his career that Corteggiano traded physical power, until he did so at Cragview in late October 2013,” FERC said.

Enforcement staff investigated Corteggiano’s conduct at Deutsche Bank, resulting in the settlement of manipulation allegations with Deutsche Bank, a civil penalty of $1.5 million and disgorgement of $172,645, plus interest, in January 2013 (IN12-4).

At the Cragview node, “Respondents’ manipulative trading enabled Vitol to avoid paying CAISO $1,227,143 on Vitol’s CRRs,” the report said. “Moreover, respondents caused $2,515,738 in market harm consisting of (a) $2,429,385 in reduced funding of CAISO’s CRR balancing account, and (b) $86,353 in losses suffered by the holders of CRR counter-flow positions at Cragview.

“Although Corteggiano was not identified by name in the Order to Show Cause in the Deutsche Bank enforcement matter, the public Enforcement staff report attached to the order explained his central role in the trading scheme and referred to him by name,” the report said.

CAISO’s CRR auction has cost ratepayers $860 million because of the difference between revenues and payments to CRR holders, the ISO’s Department of Market Monitoring has found. The ISO has tried to stem the losses through changes to its CRR auctions, which appeared to reduce the disparity between payments and income in the first quarter of 2019. (See Gas Spike Drove High CAISO Power Costs in Q1.)

Vitol was one of the companies that opposed those changes last year. (See FERC OKs Tighter Rules for CRR Auctions.)

House Presses Reliability Officials on Cyber Threats

By Michael Brooks

WASHINGTON — House Energy and Commerce Committee members seeking details about foreign cyber threats were left wanting Friday as grid reliability officials declined to discuss specifics.

Appearing before the committee’s Subcommittee on Energy, NERC CEO Jim Robb, FERC Office of Electric Reliability Director Andy Dodge and Karen Evans — assistant secretary of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) — all seemed hesitant to answer members’ questions directly. Instead, they often talked generally about their agencies’ efforts to protect the bulk electric system from cyberattacks. Sometimes they outright declined to answer, citing classified information.

Cyber Threats
The House Energy and Commerce Committee’s Subcommittee on Energy listens to NERC CEO Jim Robb on July 12. | © ERO Insider

Ranking member Fred Upton (R-Mich.) acknowledged the many security exercises the industry conducts, but he asked if any of them involved simulating cyberattacks against natural gas pipelines. Dodge said DOE held a classified security briefing, followed by a joint tabletop drill with FERC that “involved electricity industry officials, natural gas industry officials [and] all the RTOs and ISOs. And it was a rather extensive event. There were lessons learned … and the items from those we’re actively following up on.”

Neither he nor Evans said when the exercise was held. Upton followed up by asking them if their agencies were planning another exercise. Robb jumped in, speaking at length about NERC’s fifth Grid Security Exercise (GridEx), which will be held Nov. 13-14.

Rep. Scott Peters (D-Calif.) asked Evans if she knew “how many cyberattacks the electric grid sustains on … an average day.”

Cyber Threats
Karen Evans, Department of Energy | © ERO Insider

“It depends on how we talk about a cyberattack,” said Evans, who appeared to be choosing her words carefully. “We are in constant communications with the ISACs [information sharing and analysis centers], and we constantly monitor what is happening in the state of the sector as a whole. So beyond that, I am happy to come back in a more appropriate setting to give you more details if you’d like.”

“Well, you didn’t tell me a number,” Peters responded. “Do you know the number yourself?”

Evans repeated that it depends how you define a cyberattack. Peters followed up by asking if CESER was able to determine “how much of that activity is coming from state actors.” Evans gave a blank stare before smiling and saying, “So, again, I would be happy to talk about that more, but the way we are designing the system…”

“I’m not asking to tell me if it’s coming from state actors,” Peters interrupted. “I’m asking, do you know whether it’s coming from state actors? Is that something you don’t want to answer here?”

“I would like to answer that in a more appropriate setting.”

Similarly, Rep. Jerry McNerney (D-Calif.) asked Evans if she was “aware of any foreign governments embedding cyber weapons into our utility grid today to be used in possible future attacks.”

“I would reference back to the unclassified version of the Worldwide Threat Assessment,” Evans replied. “I think that the [director of national intelligence] has been very specific about what our adversaries’ capabilities are.” She said she has memorized the widely disseminated quotes from the report about Russia’s and China’s activities: They have “the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure…”

Rep. Ann M. Kuster (D-N.H.) asked Dodge whether FERC publicly discloses the names of utilities that have been assessed penalties for noncompliance with critical infrastructure protection (CIP) standards. Last month, Public Citizen filed a complaint with FERC requesting it release the names of two entities that violated 25 CIP standards between them (NP19-10, NP19-11). NERC issued penalties of $1 million against each of the entities.

Cyber Threats
Andy Dodge, FERC | © ERO Insider

Dodge said that over the past year, the commission has received “a number of” requests for critical energy/electric infrastructure information, including the identities of entities that have violated CIP standards, under the Freedom of Information Act. “We review them in excruciating detail, and we’ve determined which ones to release [and] which ones not to release,” he said. “We are still working through that, and we have released the names of some entities where we did not believe it would be a threat to security of that entity.”

Throughout the hearing, the panelists emphasized that interagency collaboration and information sharing between government and industry was critical to protecting the grid. Several representatives asked what Congress could do through legislation to help facilitate that.

“The most important thing from our perspective would be for government to be able to more rapidly declassify information, to get it into actionable insights that we can get out to industry,” Robb said. “Industry doesn’t need to know the origin, we don’t need to know the sources, we just need to know the what’s.”

Cyber Threats
Jim Robb, NERC | © ERO Insider

McNerney asked Robb if “the security clearances of utility officials was an obstacle to effective data sharing of cybersecurity information.”

“I would say yes,” Robb replied. “Just the sheer number of individuals who are waiting for a clearance and don’t yet have them is problematic.”

McNerney then asked how Congress could fix that.

“I don’t have an answer to that question, but it’s a problem that needs to be resolved,” Robb said.