Texas Public Utility Commission Chair DeAnn Walker last week took advantage of a NERC trustee’s presence at a virtual meeting to plead for ERCOT representation on the ERO’s board.
“I’m not going to surprise anyone on the board when I say what I’m about to say,” Walker said, following NERC Trustee Suzanne Keenan’s introduction during the Texas Reliability Entity Board of Directors’ meeting Wednesday. “I feel very strongly that NERC needs to consider having a member on the board from the ERCOT region that understands this interconnection,” echoing comments she made during the Texas RE board’s December meeting. (See “Walker Raises Concerns with NERC Representation,” Texas Reliability Entity Briefs: Dec. 11, 2019.)
Keenan, in her third year on the 11-member independent board, was diplomatic in her response.
“Thanks for sharing that with me,” she said. “I am on the [Nominating] Committee this year, so I will definitely take your comments back.”
Texas RE board Chair Fred Day backed up Walker, saying, “I think I speak for the entire board … we all feel that way. It’s time we were represented on the board.”
NERC’s Compliance and Certification Committee, which advises the trustees on all facets of the ERO’s compliance monitoring and enforcement program, has revised its charter to eliminate six regionally allocated seats — one for each regional entity — and replace them with six at-large seats.
Staff Adjust Well to Working Remotely
Texas RE CEO Lane Lanford said some staff could be returning to the office as soon as July 6 but noted the date has already been moved three times.
“July 6 is just another date,” he said.
Lanford said those staffers that return to the office would do so on a voluntary basis, where they will find a different workspace with signage, one-way “streets” through the cubicles and social distance requirements at the coffee machines. The Texas RE may not hold in-person meetings until 2021, though the final decision hasn’t been made.
“We’re pretty good working this way,” Lanford said. “Two years ago, when he started practicing [working remotely], I was wondering what we would ever do taking this much time off. We haven’t had too many bumps in the road.”
Texas RE CEO Lane Lanford and Director Lori Cobos, of the Texas Office of Public Utility Counsel, during a board meeting in 2019 | Texas RE
He gave kudos to IT staff, saying they were able to improve remote connectivity on the fly.
Day, who is serving his last year on the board, also said he was looking forward to some “actual face time” with staff and directors before the year is out.
“Nothing beats being in the same room, talking,” he said. “Socially distancing, of course.”
Board Approves New RDA, Budget
The board unanimously approved a new regional delegation agreement (RDA) with NERC to replace the current agreement, which expires at year-end. The RDA, which was developed with NERC’s legal staff, includes the option for a five-year extension.
NERC plans to file all six REs’ RDAs with FERC for the latter’s approval by the end of June.
The board also approved a 2021 budget of $14.2 million, a 2.8% increase from 2020, and an “unmodified” audit of Texas RE’s 2019 financial statements with no reported findings. Salaries will increase by 3.2%, primarily because of three new compliance positions.
NERC and the regional entities have temporarily expanded their self-logging program to allow registered entities to focus on their response to the coronavirus pandemic.
The self-logging program was introduced in 2015 and allows utilities, with permission of their regional entities, to log instances of potential noncompliance with NERC reliability standards that pose minimal risk to the bulk power system for future review by the ERO Enterprise, rather than submitting a self-report. Noncompliance events logged in this manner are typically resolved as compliance exceptions, which are not included in a registered entity’s compliance history for penalty purposes.
According to the guidance released on Thursday, all registered entities — regardless of whether they are already part of the program — will now be allowed to self-log instances of noncompliance that pose either a minimal or moderate risk to the BPS, as long as the noncompliance is because of “actions to address coronavirus impacts [that] disrupt, complicate or otherwise alter the normal course of business operations.”
NERC has posted a logging spreadsheet template on its website for its compliance monitoring and enforcement program (CMEP). This form should be used by all registered entities for coronavirus-related noncompliance logging, including those that are already part of the self-logging program. Utilities that have not already registered for self-logging will not be entitled to do so for noncompliance instances that are not pandemic-related and will not be considered enrolled in the program following the expiration of the guidance on Sept. 30.
“This expansion allows [registered entities] to focus their immediate efforts and resources on maintaining the safety of their workforce and communities,” NERC said in a statement. “Under this temporary expansion … potential noncompliance related to coronavirus impacts and logged consistently with this guidance is expected to be resolved without further action.”
NERC and the REs, as well as FERC, will review registered entities’ logs at least once each month. Registered entities are required to maintain evidence related to noncompliance incidents for 18 months from the date the logs are submitted to their REs.
NERC Pushes Regulatory Relief
The expansion of the self-logging program is in keeping with several previous moves to ease compliance burdens for utilities dealing with the COVID-19 outbreak. In March, NERC and FERC announced they would use “regulatory discretion” to address difficulties registered entities may have in the following categories:
Inability to obtain and maintain personnel certification for the period of March 1 through Dec. 31;
Failure to perform periodic actions required by reliability standards between March 1 and July 31; and
In addition, FERC agreed in April to defer the implementation of seven reliability standards scheduled to take effect this year. (See FERC Agrees to Defer Standards Implementation.) The commission said the delay was intended to reduce pressure on registered entities to ensure compliance with the new standards while implementing coronavirus response measures.
“We don’t want FERC and NERC to be a burden to industry while we’re in this very constrained operating posture,” NERC CEO Jim Robb told the Member Representatives Committee in April. “[We] want to [be] very clear that our commitment is to work with industry to address these issues together.”
Utilities expect their mutual assistance plans to help the U.S. electric grid weather a predicted active Atlantic hurricane season, even in light of the ongoing COVID-19 pandemic, members of the Electric Subsector Coordinating Council (ESCC) said Thursday.
In a media call, Scott Aaronson, Edison Electric Institute vice president for security planning and preparedness, and Stan Connally, executive vice president for operations at Southern Co., said April’s Easter weekend storms provided valuable information that will shape future storm response. Restoring the more than 1 million homes and businesses that lost power required ensuring that all personnel maintained suitable safety measures outlined in the outage response plan that ESCC created at the beginning of the pandemic.
2017’s Hurricane Irma | Department of Defense
“We were fortunate that we were able to return service to most of [the affected customers] within 24 hours,” Connally said. “But that happened because of the reliance on and the response of our partners. … For these storms, we had over 1,000 mutual assistance workers that responded to us from 10 different states.”
Connally and Aaronson said the response proved to be “a successful test case” for the COVID-19 protocols, with power restored quickly and no coronavirus infections reported among any of the crews that assisted with the Easter storms. But they also acknowledged that scaling up this kind of operation to deal with a major hurricane — of which there could be as many as six this year, according to the National Oceanic and Atmospheric Administration — will require high levels of cooperation from everyone involved.
As many as 19 named storms are predicted for the 2020 hurricane season, including up to six major hurricanes. | NOAA
Distancing Efforts Provide Future Value
Key challenges anticipated by the ESCC are:
ensuring personnel maintain appropriate social distance while working on service calls;
maintaining an adequate supply of personal protective equipment (PPE) for service workers; and
creating contact tracing and testing regimes to find out as soon as possible if exposed employees need to be removed from the front line.
Connally described several ways his company worked to address those issues during the recent storms. Where Southern might normally create large base camps for several thousand workers to eat, sleep and store their vehicles and equipment, the company this time broke up those camps into many smaller staging areas, along with isolating sleeping quarters. This created complications with distributing resources to many more destinations; however, the utility believes the experience will be worthwhile in the long run.
“We may be seeing some advantages of doing that,” Connally said. “For instance, getting the material [pre-distributed] may prove to be a solution that provides us some advantages in terms of restoration time. So [while] you might say there’s additional complication and logistics challenges with the COVID protocols, at the same time we may find some advantages [for] our restoration efforts.”
The social distancing measures have also provided an impetus for utilities to speed up the adoption of new communication technologies that could bring long-term benefits. Instead of gathering personnel in one place for safety or mission briefings, for example, the information can be sent to employees in the field directly, ensuring they have more time for their work.
PPE, Testing Present Ongoing Challenge
With regard to PPE and other essential items, Aaronson said the ESCC has made sure to “constantly pulse the supply chain at all levels” by keeping in contact with all relevant suppliers, and that it has not noted “a specific impact” on the supply chain and logistics despite the stress of the Easter storms. However, continued monitoring is still needed as stocks may be quickly depleted in a major outage scenario.
Testing and contact tracing are another area that still presents difficulty, as utilities usually lack adequate testing capacity to test a sudden influx of field personnel from other states or the time to test them all before they go to work. In these cases, local respondents must rely on the assurance of partner utilities that their workers have not been in contact with infected individuals while keeping distancing measures in place and making sure that all suspicious symptoms are reported as soon as possible.
Despite these ongoing complications, the ESCC remains confident that utilities can work together to ensure safe and continued operation during the hurricane season, which begins June 1. Participants say the industry’s spirit of collaboration will be key.
“What is interesting about this is [that] so much of our continuity planning in this industry actually is rooted in pandemic,” said Aaronson, referring to previous outbreaks such as SARS, MERS, and the avian and swine flus. “Those were all potential threats that presented really interesting thought exercises … [that] really did inform a lot of how this industry works together to do contingency planning against all threats.”
FERC this week approved a procedure for “critical” New England generators and transmission operators to obtain compensation for compliance with NERC rules but said it would not cover past expenses (ER20-739).
The ruling allows owners of assets judged critical to the derivation of interconnection reliability operating limits (IROL) to seek compensation for costs of complying with NERC’s critical infrastructure protection (CIP) reliability standards.
The commission approved ISO-NE’s proposed Tariff Schedule 17, allowing facility owners to seek cost recovery through Federal Power Act Section 205 filings effective March 6.
ISO-NE said there are 27 generation units at 15 plant locations and one merchant transmission facility that are IROL-critical facilities.
The RTO said the generators designated as IROL-critical “protect other control areas from unanticipated events that might occur inside New England and maximize internal transmission capability, which benefits all internal transmission customers. These IROL-critical facilities predated the IROL-critical designations and were thrust into compliance requirements not originally anticipated in the economics of the projects, and not recoverable through existing market mechanisms.”
The facilities’ compliance with CIP standards “allows the ISO to operate the system with higher limits without unacceptable risk. Conversely, compromised IROL-critical facilities’ controls, for example, can lead to inadvertent operation of the system using incorrect limits. Operating the system based on faulty limits can result in local or widespread system instabilities, potentially leading to uncontrolled separation, cascading outages and blackouts in the New England and neighboring control areas,” ISO-NE said.
In joint comments, NextEra Energy Resources, Vistra Energy, NRG Energy, FirstLight Power, Cogentrix Energy Power Management, Cross-Sound Cable Co. and Dynegy Marketing said they have spent “several million dollars to meet their higher reliability requirements thus far” on six facilities with a capacity of 3,598 MW designated as IROL-critical. They said they should be allowed to collect all historic costs, not only going-forward costs.
Cross-Sound Cable Co., which operates a 24-mile submarine cable under Long Island Sound to connect the New England and Long Island electric grids, is a merchant transmission facility that ISO-NE has designated as IROL-critical. The 330-MW HVDC line terminates on Long Island at the Shoreham converter station (pictured). | Cross-Sound Cable Co.
ISO-NE took no position on whether prior costs should be recoverable, saying the commission should decide based on individual asset owners’ Section 205 filings. The New England States Committee on Electricity (NESCOE) opposed recovery of prior costs, saying it would violate FERC’s rule prohibiting retroactive ratemaking.
The commission sided with NESCOE, saying it would consider only CIP costs incurred on or after the effective date of a Section 205 filing.
“Under FPA Section 205, rate changes may be prospective only, and, under the rule against retroactive ratemaking, the commission is prohibited ‘from imposing a rate increase for [power] already sold’ or ‘adjusting current rates to make up for a utility’s over- or undercollection in prior periods.’”
ISO-NE — the NERC reliability coordinator for New England — said facilities it identified as IROL-critical must comply with CIP reliability standards for the medium-impact category, subjecting them to significant compliance costs compared to low-impact facilities, which are not recoverable under its Tariff.
Schedule 17 includes a template for recording incremental compliance expenses, including categories for labor, equipment and hardware; software; physical improvements; and administrative and regulatory costs.
ISO-NE said it will charge the costs to transmission customers on a pro rata basis based on the customer’s monthly regional network load or average monthly through-or-out service reservation.
The filing won the support of 64% of the New England Power Pool, just below the two-thirds threshold required for the organization’s formal support.
Rather than making periodic Section 205 filings, the facility owners asked FERC to allow them to make informational formula rate filings with data on actual costs incurred.
The commission declined to set a formula rate for cost recovery but said facility owners may seek formula rate treatment in their Section 205 filings.
The California Public Utilities Commission unanimously approved Pacific Gas and Electric’s Chapter 11 reorganization plan Thursday but warned it will now have regulatory mechanisms to end the utility’s century-old electric monopoly should it fail to ensure public safety.
Part of the proposed decision approved by the CPUC provides for a detailed six-step process of enforcement and oversight by the commission that could eventually lead to it placing conditions on — or revoking — PG&E’s certificate of public convenience and necessity (CPCN), which grants the utility monopoly status over 70,000 square miles of Northern and Central California, with its 5.4 million customer accounts.
“This is the time for a PG&E to emerge from bankruptcy that must be reborn with safety as its top priority,” Commissioner Clifford Rechtschaffen said. “Your future depends on it. There’s nothing more or less than that at stake.”
The CPUC decision also required PG&E to replace most of its board members and upper management, and to link executive compensation to safety performance. The utility agreed to break up its operations into eight regional entities and to allow a commission-appointed observer to report on its progress from inside corporate headquarters.
CPUC President Marybel Batjer said she believed the regulations will drive change at PG&E, but if they don’t, the commission is prepared to take further action.
“This transformed company must move from one that is held tightly in the grip of continual correction, of failures, to one that is a model company that is respected for how it serves its customers and community,” Batjer said.
CPUC President Marybel Batjer | California State Assembly
The CPUC’s acceptance of PG&E’s Chapter 11 plan was necessary for it to exit bankruptcy, along with the U.S. Bankruptcy Court’s approval, which could come as soon as next week. (See related story, Improper Email Delays CPUC Vote on PG&E Plan.)
Last year’s Assembly Bill 1054 tasked the CPUC with ensuring that PG&E’s reorganization plan serves the public interest, including “the electrical corporation’s resulting governance structure … in light of [its] safety history, criminal probation, recent financial condition and other factors deemed relevant.”
Government investigations found faulty PG&E equipment started the November 2018 Camp Fire, the deadliest in state history, as well as devastating wildfires in 2017 and 2015 and the San Bruno gas pipeline explosion in 2010.
‘We Need a Public Utility’
The series of catastrophes prompted critics to call for a state takeover of PG&E, especially after the utility filed for bankruptcy protection in January 2019 as it faced massive wildfire liabilities.
Gov. Gavin Newsom was among those who threatened state intervention should the company fail to meet his demands for a new board and management, though he ultimately agreed to PG&E’s Chapter 11 plan with the CPUC’s added conditions.
Dozens of public speakers in Thursday’s hearing repeated calls for a public takeover, telling commissioners that PG&E’s Chapter 11 proposal would not do enough to prevent future wildfires or reform its safety culture. Public comments filled the first two-and-a-half hours of the four-hour voting meeting.
Many speakers said PG&E’s primary mission will remain earning profits and rewarding shareholders, the same behavior that they said led to the fires of 2017 and 2018. In April 2019, federal Judge William Alsup, who is overseeing PG&E’s criminal probation stemming from the San Bruno gas explosion, said the utility paid out $4.5 billion in dividends in recent years while neglecting tree trimming and other line maintenance, resulting in the wildfires.
Charlotte Quinn, with the Democratic Socialists of America, told the commissioners that PG&E needs to be accountable to voters, not shareholders.
“We need a public utility,” Quinn said. “The existing and proposed for-profit model is the cause of fires and explosions, death and destruction and old, unsafe infrastructure. Until the profit motive is removed, the energy grid will remain unsafe for communities, just as it has been proven over and over again.”
Commissioner Martha Guzman Aceves said she shared such concerns but was reassured by a bill in the State Legislature that could provide a means for turning PG&E into a public-benefit corporation called Golden State Energy. The measure, Senate Bill 350, by Sen. Jerry Hill, was scheduled for a hearing Thursday in the Assembly Utilities and Energy Committee.
Statutory authority for replacing PG&E as a for-profit monopoly has been lacking, Guzman Aceves noted.
“Fortunately today, through the governor’s leadership and the legislative leadership, we have Sen. Hill’s bill, SB 350, that will soon provide us as a state with the tools to replace PG&E with a customer-elected public option should they fail,” Guzman Aceves said. “This bill will give ratepayers a genuine alternative. If PG&E fails to provide safe, reliable and affordable energy service, then the commission could petition the court to appoint a receiver or revoke PG&E’s CPCN.”
Pacific Gas and Electric’s chief financial officer took to the virtual stand in bankruptcy court Thursday to face questions about the “feasibility” and “fairness” of the utility’s reorganization plan for the thousands of victims of wildfires sparked by its equipment.
The second day of the confirmation hearing for the plan once again played out over a Zoom conference call and not in the U.S. Bankruptcy Court in San Francisco, where the utility filed for Chapter 11 in January 2019.
After fire victims last week voted in favor of a PG&E reorganization plan that will leave those victims with a $13.5 billion trust half-funded by utility stock, Thursday’s hearing provided dissenters a final chance to sway the judge against approving that outcome. (See Trial Begins to End PG&E Bankruptcy.)
Tom Tosdal, an attorney representing about 1,000 victims of the 2018 Camp Fire, pressed CFO Jason Wells on the soundness — and justness — of the trust.
Of the nearly 40 classes of claimants in the bankruptcy proceeding, Tosdal noted, only the fire victims were being compensated with stock whose value is tied to PG&E’s future performance — a risk in the face of ongoing wildfire threats that could bring more claims against the utility in the future.
Tosdal said the fire victims were being treated worse than subrogation claimants poised to receive full cash settlements. He said the subrogation class itself consisted of two “types”: insurers that have paid out claims to their customers and PG&E shareholders that purchased subrogation claims against the company before it entered bankruptcy.
Tosdal cited the hedge fund Baupost, a PG&E investor that starting in November 2018 bought $6 billion in claims against the utility for 30 to 35 cents on the dollar — prompting an objection from PG&E attorney Theodore Tsekerides.
“I don’t think that’s relevant to any of the discussions of the classification issue — who holds those claims. They are what they are,” Tsekerides said.
“It goes to fairness, your honor,” Tosdal said. U.S. Bankruptcy Judge Dennis Montali allowed Tosdal to proceed.
Tosdal asked Wells if Baupost owned many shares of PG&E common stock.
“They do,” Wells replied.
“And do you understand that Baupost bought those subrogation claims at a discount, meaning less than 100% on the dollar?” Tosdal asked.
“I do,” Wells said.
But Wells demurred when Tosdal then asked if he knew that PG&E investors paid a “substantial discount” in their purchase of company subrogation claims.
“So, when this bankruptcy ends, and the subro class is paid $11 billion cash, those PG&E investors, who purchased subro claims against their own company at a substantial discount, stand to make a big profit, correct?” Tosdal continued.
Tsekerides again objected, saying the issue of the discount is “completely irrelevant” to the issue of confirming the bankruptcy plan. Such claims are traded “all the time” in Chapter 11 cases, he said.
Montali turned to Tosdal: “Why is it helpful for to me to make a determination? It is a fact of life that claims are traded at discounts in lots of companies. Why is it relevant to my determination?”
“Because, your honor, when we started this case, I remember that you told everybody on the record, [in the] first hearing, that the most important group in this case to be taken care of are the fire victims,” Tosdal said. “And instead, what is happening here is that the fire victims are getting stock instead of cash, and the effect of that is to provide investors in this company, who have purchased subrogation claims at a discount, with billions of dollars of profit. That is the reality, whether it’s customary for there to be a second market.”
Montali shut down Tosdal’s argument, sustaining Tsekerides’ second objection.
“The fact that an investor, whether it be Baupost or Joe Blow, bought a claim at a discount has nothing to do with how that person will end up being treated,” the judge said. “Your argument tells me that you or your clients don’t like the plan. But the plan isn’t going to turn on the discount rate that an investor paid or didn’t pay. The fact of the matter is a subrogation creditor who didn’t sell his claim at a discount is going to be treated the same as a speculator who bought another subrogation claim at a discount. It doesn’t matter.”
The question of the “feasibility” of the wildfire victims’ trust was at the heart of questions from Will Abrams, an outspoken victim of the 2017 fires that ravaged California’s wine country and burned out a section of Santa Rosa. Abrams focused on the concern that claims from future wildfires could compromise the value of a trust heavily dependent on the company’s share price.
“Would you agree that more wildfires are a risk to the feasibility of the plan?” Abrams asked Wells.
“The risk of catastrophic fires is something that we’re actively managing,” Wells responded. “The combination of all of the work we’re doing to prevent those fires, as well as the passage of Assembly Bill 1054, create the conditions that would make our plan financially feasible.” Passed by the California legislature last year, AB 1054 establishes a wildfire insurance fund for the state’s utilities. PG&E must exit bankruptcy by June 30 to qualify for coverage under the bill.
Abrams questioned PG&E’s ability to mitigate future wildfire risk, citing its past record and what he called its current lack of preparedness. Wildfires are up 60% in California for the first four months of this year compared with last, according to Gov. Gavin Newsom.
Abrams pointed to recent finding by U.S. Judge William Alsup, who is overseeing PG&E’s criminal probation for causing the 2010 San Bruno pipeline explosion, that the company must quickly improve its safety performance to avoid sparking new wildfires. (See Judge Orders PG&E to Improve Line Inspections.)
Overcoming an objection from Tsekerides, Abrams pressed Wells about the number of C-hooks the company has replaced in its aging transmission network (Wells didn’t know) and how much of its annual vegetation management program it has completed this year (one-third as of the end of the first quarter, Wells said).
While Montali provided Abrams with ample time to argue his points and air his views, the judge also evinced skepticism that he will be swayed by his challenge to the utility’s plan.
“You, for one, don’t have a lot of confidence in PG&E going forward, but that’s not the point,” Montali told Abrams. “I have to see if the Bankruptcy Code has been satisfied, and it gets [to be] more than that, because the governor has to be satisfied; the Public Utilities Commission has to be satisfied. And you may be unsatisfied, but if all of those things come together, I then have to be persuaded that PG&E is not likely to need further reorganization under the bankruptcy laws.”
The California PUC on Thursday voted unanimously to approve PG&E’s bankruptcy plan, a key step in moving the plan forward. (See related story, CPUC Approves PG&E Bankruptcy Plan.)
Confirmation hearings will continue into next week, when the bankruptcy court will listen to legal arguments related to the plan.
American Electric Power on Wednesday said it has received enough regulatory approvals to fully move forward with its 1,485-MW North Central Wind Project in Oklahoma.
AEP will invest about $2 billion in the project, which consists of three wind farms and will serve the company’s Southwestern Electric Power Co. (SWEPCO) and Public Service Company of Oklahoma (PSO) affiliates.
The Louisiana Public Service Commission on Wednesday approved a settlement agreement that authorizes SWEPCO — which serves parts of Louisiana, Texas and Arkansas — to purchase 810 MW of nameplate wind capacity from the project. The PSC’s approval included a “flex-up” option that could increase Louisiana’s allocation of that capacity from 268 MW to an estimated 464 MW if Texas regulators do not approve the project.
AEP says the North Central Wind Project will save SWEPCO customers $30 billion over three years. | AEP
The Arkansas Public Service Commission also accepted an option to increase the state’s allocation — from 155 MW to about 268 MW if Texas rejects it — when it approved the project earlier this month. The Texas Public Utility Commission’s agenda for its open meeting Friday does not list the project for consideration.
“This investment is expected to save our customers approximately $3 billion over the next 30 years while supporting economic development in our communities,” AEP CEO Nick Akins said. “We will continue to seek approval to provide a share of this renewable energy to our SWEPCO customers in Texas, as we believe the projects offer significant benefits to customers across our SWEPCO footprint.”
PSO received final Oklahoma Corporation Commission approval Feb. 20 for 675 MW. FERC has also approved the project.
The three facilities are being developed by Invenergy in north-central Oklahoma. One facility is expected to be completed by the end of 2020, the other two by the end of 2021.
North Central Wind Project’s three wind farms are slated to be online by 2021. | AEP
The project replaces the $4.5 billion Wind Catcher Energy Connection. The plan involved a 2-GW wind farm and a 360-mile transmission connection, but it was canceled in 2018 by AEP when the Texas PUC rejected SWEPCO’s attempt to acquire a 70% interest in the project. (See AEP Cancels Wind Catcher Following Texas Rejection.)
AEP’s regulated integrated resource plans call for the addition of more than 8 GW wind and solar energy between 2020 and 2030.
A proposal to open end-of-life (EOL) transmission projects in PJM to regional planning and competitive bidding was narrowly defeated in a vote at the Markets and Reliability Committee meeting Thursday.
The “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others failed with a sector-weighted vote of 3.23 (65%). The proposal needed a sector-weighted vote of 3.33 (66.7%) for passage.
The proposal won support from 100% of the End-Use Customers, 97% of the Electric Distributors and 71% of Generation Owners. But it was opposed by 59% of Other Suppliers and all but two of 14 Transmission Owners.
Transmission owners would have been required to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.
A proposal by PJM also failed with a sector-weighted vote of 1.77 (36%) at the MRC.
Despite failing at the MRC, supporters of the joint stakeholders proposal unsuccessfully attempted to bring it to a vote at the Members Committee meeting in the afternoon after Chair Steve Lieberman, of AMP, recused himself from the meeting.
Number of baseline vs. supplemental projects (2010-2019) | PJM
After about 90 minutes of parliamentary jousting, the stakeholders called a vote to suspend the rules to allow consideration of their proposal, but the motion fell short of the two-thirds needed with a vote of 3.08 (62%).
ODEC’s Mark Ringhausen, who presented the joint stakeholder package, said it would allow for Order 1000 competition in EOL projects that would ultimately lead to lower costs for ratepayers.
Ringhausen highlighted the TOs’ May 7 notification that they were considering a Federal Power Act Section 205 filing to amend the Tariff as an alternative to the proposals under consideration. Ringhausen said the TO filing at FERC after June 8 would be similar to the PJM proposal, which had “almost zero transparency,” giving the TOs control over most of the future transmission planning.
Dave Souder, PJM’s senior director of system planning, presented the RTO’s package, which would have required TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions.
PJM cited language in the Consolidated Transmission Owners Agreement (CTOA) that allowed TOs to retain the authority to “build, finance, own, acquire, sell, dispose, retire, merge or otherwise transfer or convey all or any part of its assets, including any transmission facilities.” The RTO also said its role was limited by two FERC rulings involving ‘Asset Management’ not Subject to Order 890, FERC Rules.)
“At the end of the day, we’re going to have to agree to disagree,” Ringhausen said of the stakeholders’ insistence that their proposal complies with the CTOA and the PJM Tariff. “Hopefully, we can get this in front of FERC and make them look at it and say what the right outcome should be here for this process.”
Mike Gahimer of the Indiana Office of Utility Consumer Counselor said PJM “misrepresented” the FERC orders. In the order involving Southern California Edison, Gahimer said, FERC stressed the limited scope of asset management as “looking at components, not entire substations or transmission lines for replacement.”
Gahimer said the joint stakeholder proposal didn’t involve components, but rather lines and substations. “I don’t think anyone, including the most biased among us, would claim that the projects at issue here are day-to-day projects,” he said.
AMP’s Ed Tatum said that with the amount of transmission infrastructure that’s going to have to be replaced in the next decade, careful planning is going to be needed. He said PJM’s expertise is essential to ensure that the planning for the grid of the future is simply not rebuilding the transmission system of the past. He fears the future of transmission planning will be moved out of the jurisdiction of PJM and back to the TOs without coming up with compromises.
“That’s a great concern from the standpoint of those who believe transmission and an independent transmission planner is a cornerstone to competitive markets,” Tatum said. “We think that PJM should be the independent planner. We think they bring value from a more holistic look.”
Thursday’s votes are unlikely to bring an end to the billion-dollar debate over control of EOL projects.
The TOs have scheduled a webinar from 2 to 4 p.m. Monday to discuss their potential Attachment M-3 filing. They could file the attachment after the 30-day comment period expires June 8.
Supporters of the joint stakeholders proposal could file a complaint with FERC contending the current procedures are not just and reasonable.
NYISO has suspended the sequestration of its control room operators but is in no hurry to bring its other staff back to ISO offices as New York begins its recovery from the coronavirus pandemic, CEO Rich Dewey told the Management Committee on Wednesday.
The ISO ended sequestration for its Krey Boulevard control center operators on May 4 and that for Carman Road two weeks later, Dewey said. “We think we’re in a reasonable posture to suspend the sequestration of those staff members,” he said, adding that the ISO is prepared to resume sequestration if there is a resurgence of infections in the region.
For now, Carman Road staff are handling the day shift, with Krey Boulevard working nights.
Other NYISO staff are “almost exclusively” continuing to work from home while the ISO tracks the state’s reopening plans.
Although the ISO does have return-to-office plans, Dewey said it will be “conservative” in implementing them. “There’s no particular schedule for when we will start phasing people back into the office,” he said. With telework “working pretty well … we’re not going to be in a rush to change that posture.”
Dewey said the joint Board of Directors/Management Committee meeting scheduled for June 15-16 at the Sagamore Resort on Lake George has been converted to a virtual session. Like past in-person gatherings, the meetings will include both general sessions involving all attendees, and breakouts with individual board members and about 10 stakeholders.
“It’s very important for our board members to get feedback from market participants,” Dewey said. “I think we’ve demonstrated that the technology is quite capable. … We won’t have the normal social interaction, but we’ll do the best we can under the circumstances.”
The topics will include the “Grid in Transition” and “Navigating Uncharted Territory,” which will explore post-pandemic economic changes that may impact the sector.
Summer Capacity Assessment
NYISO’s baseline analysis shows a 1,721-MW capacity margin surplus for the summer peak in 2020, a drop of 506 MW from 2019, said Wes Yeomans, vice president of operations.
The 90th percentile forecast shows a 193-MW shortfall, a decrease of 616 MW from last year. Such extreme conditions might require the ISO to either tap its 2,620 MW of operating reserves or call on emergency operating procedures, including voltage reductions, emergency purchases and voluntary load reductions, for up to 3,080 MW.
New York Control Area summer peaks: 2000-2019 | NYISO
The summer assessment shows 2,273 MW in generation deactivations, including the state’s last two coal-fired plants (the 155-MW Cayuga Unit 1 and the 655-MW Somerset plant) and the retirement of Unit 2 of the Indian Point nuclear plant (1,299 MW), which shut down at the end of April.
The ISO has one new generating asset, the 1,177-MW Cricket Valley combined cycle plant in Dover, N.Y.
60-minute Rule for Energy Storage
The Management Committee approved changes to section 4.4.3.1.1 of the Services Tariff to only award energy storage resources (ESRs) energy schedules that are sustainable for at least 60 minutes during a reserve pick-up (RPU) event.
The change was prompted by concern that during an RPU, real-time dispatch may award a larger energy schedule than an ESR can sustain for 60 minutes, as required by the Northeast Power Coordinating Council.
This can occur because the real-time dispatch/corrective action mode used to perform an RPU must issue updated schedules very quickly and thus only looks out 10 minutes.
Potomac Economics’ 2019 State of the Market Report for NYISO adds five new recommendations while concluding the ISO’s markets “performed competitively” in 2019.
Potomac’s Pallas LeeVanSchaick told the NYISO Management Committee on Wednesday that 2019 energy prices were the lowest in the past decade, dropping 22 to 34% from 2018. He cited a 22 to 41% drop in natural gas prices from expanded production, and muted demand from a mild winter and summer.
Mild weather, energy efficiency and behind-the-meter solar generation contributed to the lowest average load in more than a decade, the ISO’s Market Monitoring Unit said.
Fuel type of real-time generation and marginal units in New York, 2017-2019 | NYISO
Capacity prices also fell to 8 to 26% of the net cost of new entry (CONE) outside of New York City, thanks to reduced local capacity requirements and new capacity additions. Although New York City prices rose, they still represented only 58% of net CONE. “That’s an indication of significant capacity surpluses,” LeeVanSchaick said.
The five new recommendations are in addition to 17 from prior reports.
Real-time energy prices, natural gas prices and congestion in 2019 | NYISO
Only one of the new recommendations — modifying the “Part A” test to allow public policy resources to obtain exemptions when it would not result in price suppression below competitive levels — was identified as a high priority. The MMU said the change is needed to ensure buyer-side mitigation (BSM) rules are balanced between protecting the market from price suppression and facilitating the state’s desire to control its resource mix.
“The BSM measures were originally designed to prevent entities from suppressing capacity prices below competitive levels by subsidizing uneconomic new entry of a conventional generator,” the Monitor said. “The BSM measures are not intended to deter states from promoting clean energy and other legitimate public policy objectives.”
It said it supports a plan NYISO developed with stakeholders that allows public policy resources to avoid mitigation if enough existing capacity exits the market, or if demand increases enough to boost capacity requirements. The proposal was filed with FERC on April 30 (ER20-1718).
The MMU also recommended that:
Day-ahead and real-time reserve clearing prices should incorporate reserve constraints for Long Island. Currently reserve providers on Long Island are paid clearing prices for the larger Southeast New York region. Changing the compensation would improve incentives and “provide better signals to new investors in … the long term,” the Monitor said.
Increase the offer/bid floor from -$1,000/MWh to -$150/MWh. Negative prices are used when ISO operators reduce external interface limits or curtail external transactions to maintain transmission security on an external interface. In this rare situation, external transaction schedulers can buy power at “arbitrarily” low prices, resulting in uplift for NYISO customers. “We recommend raising the bid and offer floor to a level that is closer to the range of potential avoided costs of supply for generation resources,” the Monitor said. “Negative $150/MWh should be more than adequate to provide such flexibility.”
Translate the annual revenue requirement for the demand curve unit into monthly demand curves reflecting their reliability value. NYISO’s capacity market currently is divided into six-month summer and winter capability periods with a single capacity requirement and demand curve for each, although the reliability value of resources is much greater in high-demand July than the shoulder month of October. The bifurcation “may lead to inefficient incentives for resources that are not consistently available during all 12 months,” the Monitor said. It recommended switching to monthly capacity demand curves with a minimum reference point high enough to ensure resources have incentives to coordinate planned outages with the ISO. The remainder of the demand curve unit’s annual revenue requirement would be allocated in proportion to the marginal reliability value of capacity across the 12 months. “These changes would concentrate the incentives for resources to sell capacity into New York during the peak demand months of the summer (i.e., June to August),” it said.
Translate the demand curve reference point from installed capacity (ICAP) to unforced capacity (UCAP) terms based on the demand curve unit technology. The capacity demand curves currently are based on net CONE, estimated in ICAP terms and then converted into UCAP based on the regional average derating factor, which reflects the forced outage rates of the existing fleet and UCAP-ICAP ratios of intermittent resources. This technique results in the monthly capacity demand curves being set higher than if the derating factor of the demand curve technology were used. “This inconsistency will become more pronounced as additional intermittent resources are added to the system,” the Monitor said.
