The California Public Utilities Commission on Thursday adopted fines and penalties of $125 million against Pacific Gas and Electric for starting the 2019 Kincade Fire, using a new enforcement tool that caused unusual discord among the CPUC’s five commissioners, who tend to vote unanimously.
The new expedited enforcement measure, called an administrative consent order (ACO), is a settlement process intended to reduce the time it takes the CPUC to hold utilities accountable for safety violations in an era of catastrophic wildfires. Other enforcement proceedings, such as the commission’s order instituting investigation, can take years to complete.
The CPUC created its new mechanism in November 2020 when it adopted a revised policy to promote timely enforcement of safety violations.
“The addition of these tools to the CPUC’s enforcement options in 2020 moved the CPUC’s practices more in line with the enforcement practices of many other state and local enforcement agencies,” the commission said in a statement last month.
The CPUC used its ACO option for PG&E in the Kincade Fire and for Southern California Edison (SCE) in the major fires of 2017/18, including the Thomas and Woolsey fires. The CPUC was set to take up an agreement with SCE to impose $550 million in fines and penalties for the catastrophic blazes on Thursday but moved the matter to its Dec. 16 voting meeting pending further review.
Commissioners voted 3-2 to approve the agreement between PG&E and the CPUC’s Safety and Enforcement Division that levied $40 million in fines and denied the utility $85 million in cost recovery for removing abandoned transmission lines.
A disused but energized transmission line leading to The Geysers, Calpine’s 650-MW geothermal plant in Sonoma and adjoining counties, started the Kincade Fire when a jumper cable broke, sparking dry vegetation below, an investigation by the California Department of Forestry and Fire Prevention found. The blaze burned nearly 78,000 acres of the region’s forested hills and famed wine country, destroying 374 structures and injuring four firefighters.
The agreement between PG&E and the CPUC settles only the claims of state regulators.
Commissioners at Odds
Commissioners Darcie Houck and Genevieve Shiroma, who voted against the order, said they agreed with commenters such as The Utility Reform Network that the matter deserved a longer and more in-depth public airing.
Houck noted that PG&E’s equipment caused the San Bruno gas pipeline explosion in 2010 and a series of catastrophic wildfires over the last seven years that killed more than 100 people. The CPUC has repeatedly criticized PG&E in official letters for its alleged safety failures, including five times in the past year alone, she said. (See CPUC Applies New Safety Metrics to PG&E.)
“Given the number and severity of these events, I believe that we should be providing greater scrutiny to the proposal before us,” Houck said.
“Investigation and resolution of a large-scale utility-caused disaster through a black-box settlement and resolution outside of a more formal process … is concerning to me,” she said. “It excludes impacted communities, ratepayer advocates and the public from being able to provide meaningful input up front as to the reasonableness of the proposal, potential rate implications and recommendations … [about] changes in utility operations.”
Those who voted for the agreement said they believed it achieved a just result in far less time than the CPUC’s traditional investigation and enforcement process.
“When it comes to our enforcement actions, I have been very troubled by the time that it takes, in some cases five to six years … and I’m not sure that’s doing quite as much justice as something that is akin to what’s before us, which is far more prompt and what I think is a fair outcome,” Commissioner Martha Guzman Aceves said.
CPUC President Marybel Batjer and Commissioner Clifford Rechtschaffen joined her in voting for the ACO.
“With the adoption of the administrative consent orders as part of our enforcement policy, this was a step forward in giving our expert safety and enforcement staff new tools to bring timely enforcement actions, all with the intention of driving accountability from the utilities and in the end to create a more-safe system for our customers,” Batjer said.
PG&E Disputes Allegations
The CPUC did not require PG&E to admit to any safety violations as part of the agreement.
The three main violations that formed the basis of the agreement included allegations by the CPUC’s Safety and Enforcement Division (SED) that PG&E had disconnected one of its lines from a mothballed portion of The Geysers plant but had “left the jumper cables on [one tower] attached to the ends of suspension insulators that were hanging freely from the tower arm.” That “allowed for more than typical movement of the suspension insulator string” causing the jumper cable to wear and break loose, the CPUC said.
“Accordingly, SED asserts the Geysers #9 line, as left by PG&E, was not constructed, or maintained, for its intended use,” the agreement said.
PG&E denied the allegations, contending, for example, that prior to the Kincade Fire, there were “no engineering standards, design drawings or guidance documents in the transmission industry that referenced the specific [tower] jumper configuration or that recommended or discouraged that specific configuration.”
The company said in a statement last week that it had accepted the settlement because it would allow “all parties to move forward from the fire and permit us to focus on compensating victims and making our energy system safer.”
Limited natural gas pipeline capacity and global supply chain issues with oil and LNG put the New England grid at heightened risk of emergency actions — including controlled outages — this winter, ISO-NE CEO Gordon van Welie told reporters Monday.
ISO-NE CEO Gordon van Welie | ISO-NE
The RTO anticipates having adequate capacity to meet forecast peak demand of 19,710 MW during average winter weather conditions of 10 degrees Fahrenheit and 20,349 MW if temperatures reach below-average conditions of 5 F, with both projections about 2% lower than last year’s forecasts.
The National Oceanic and Atmospheric Administration this year is projecting a warmer than average winter in New England. “If this forecast holds true, and we hope it does, the ISO expects to have the resources needed to meet consumer demand throughout the winter season,” van Welie said during a press briefing.
But he said uncertainty over fuel supplies “could put the region in a more precarious position than past winters and force the ISO to take emergency actions up to and including controlled power outages. These controlled power outages would be a last-resort action to prevent a regionwide blackout, which would take many days or weeks to restore.”
Risk Factors
Van Welie said three variables will impact the RTO’s ability to provide adequate electricity: natural gas supplies, always tight in winter because of competing heating demand; the availability of oil and LNG; and “weather events becoming more frequent and more extreme.”
He noted that current storage levels of oil and LNG are lower than in recent winters and that European and Asian LNG prices are now as much as double those in New England.
“If you were a supplier of LNG, where would you send your cargoes? To Europe or Asia or New England? I mean, I think the answer is pretty obvious,” he said. “In past winters, we’ve had the reputation of being the highest-priced gas market in the world, and so there was a really strong financial incentive to send LNG cargoes to New England. That dynamic has flipped for this winter.”
Need to Communicate with Public
Peter Brandien, vice president of system operations and market administration, said the RTO is planning for the winter based on what it learned from the cold spell of 2017/18 — when all major cities in New England had average temperatures below normal for at least 13 consecutive days, despite the forecast of a mild season — and the recent load sheds in California and Texas.
Brandien noted that CAISO had to shed load during a heat wave because it ran out of energy as the renewables “ramped out.”
“After they shed load, and then communicated the tight situation that they were in, they ended up getting about 3,000 MW of additional capacity that they did not realize was available to them. When people really understood the situation, they got a lot better conservation than they had leading into the event,” he said. “So part of what we’re trying to do here is really educate everybody on where we are and understand that when we do go out for conservation, we’re going out for conservation to try to keep everybody with electricity and try to head off” load sheds.
Van Welie said there were also lessons from the outages in Texas during the February winter storm, although he emphasized “our system is better winterized, meaning the power plants, transmission lines and other equipment needed to produce and deliver electricity can better withstand cold temperatures.” (See FERC, NERC Release Final Texas Storm Report.)
“Watching what played out in Texas, and realizing that most people in this region don’t understand how vulnerable we are when it gets cold, we thought that it’s time for us to start communicating more openly about these risks,” he said. “We’re not trying to panic anyone; we’re not trying to cause undue alarm. We need people to understand how vulnerable it can be under the wrong set of conditions, and that this region hasn’t yet solved this problem.”
The New England region depends on natural gas as the balancing energy source, using gas to produce 50 to 60% of its electrical energy today.
“And yet we know we have this constraint in the winter, so we turned to burning imported gas, essentially LNG, or imported oil, so the question is how do you start displacing that?” he said.
Siting Woes, EE
Van Welie said some technological solutions, such as small modular nuclear reactors, would be unlikely to win siting permission in New England.
The region also has not yet taken other mitigating measures such as increasing the imports of hydroelectricity from Quebec. Van Welie said he was “disappointed” with the inability to complete the New England Clean Energy Connect (NECEC) transmission line, which would deliver hydropower from the province to Massachusetts.
The project’s developer last month halted line construction, and Maine regulators suspended its environmental permit after Gov. Janet Mills certified a negative referendum vote and asked the company to stop work. (See NECEC Halts Tx Line Construction, Regulators Suspend Env. Permit.)
“If it doesn’t go ahead, I think we’ll find other paths,” van Welie said.
The region is going to have to spend more in order to get transmission landlines sited because people don’t want to see such lines, but burying them incurs a much higher cost, he said.
New England is spending more than $1 billion a year on energy efficiency, which has dramatically clipped the growth in electricity usage in the region. But the wave of electrification coming will add more demand to the grid, he said.
“I think we will continue to need to do both energy efficiency as well as look to solve for the supply side of the equation,” he said.
Van Welie said the region may need to consider adopting something like the two-week energy reserve he’s seen in the Nordic countries.
“I think that’s a discussion to be had,” van Welie said. “It’s probably some combination of the LNG, imports from Hydro-Quebec, [and] in-region storage of LNG and oil. Then the big question will be how do we get off the fossil fuels? What do we replace the fossil fuels with? Because it cannot be the answer in the long run.”
Avangrid’s (NYSE:AGR) proposed $8.3 billion acquisition of PNM Resources (NYSE:PNM) appeared in peril last week after a former cybersecurity contractor alleged that the company conspired with suppliers to buy “tens of millions” in overpriced and unnecessary security equipment and services to boost profits. The company may also face increased scrutiny from regulators in New York and New England as a result of the allegations.
In a Nov. 29 lawsuit filed in the U.S. District Court for the Southern District of New York, Security Limits Inc. (SLI), of Jessup, Pa., and CEO Paulo Silva accused Avangrid and its Spain-based parent Iberdrola (OTCMKTS:IBDRY), of a “brazen racketeering scheme, replete with bid-rigging, accounting manipulation [and] warehouses built solely to house mountains of unused equipment procured under bogus pretenses.” SLI is seeking more than $110 million in damages from the utility and others that it says stole SLI’s proprietary business secrets (Case No. 21-CV-1012).
Avangrid, which denied the allegations, responded with its own suit Saturday accusing Silva of extortion, saying he made the allegations after the utility refused to rehire his company. Avangrid’s suit, filed in Santa Fe County, N.M., cites emails he sent last August threatening to make his allegations to the New Mexico Public Regulation Commission (PRC) after the company declined to award SLI a contract.
Silva spoke at PRC meetings Aug. 9 and again Dec. 1, urging the regulators to reject Avangrid’s bid for PNM, parent of Public Service Company of New Mexico and Texas-New Mexico Power (20-00222-UT).
In its countersuit, Avangrid said Silva’s allegations “made obtaining approval from the PRC more difficult and more expensive.”
Three of the five members of the commission said at Wednesday’s meeting that they were leaning toward accepting a hearing examiner’s recommendation that they reject the purchase. PRC Chairman Stephen Fischmann cited Avangrid’s “absolutely horrible record of running U.S. utilities.” Commissioners Cynthia Hall and Theresa Becenti-Aguilar also expressed opposition. The PRC has scheduled action on procedural orders in the merger docket on its meeting agenda for Dec. 8.
State Regulators React
In his appearance before the PRC on Wednesday, Silva said that Avangrid’s “conduct artificially raised rates paid by consumers in New York and illegally enriched Avangrid’s favorite … bidders.” Avangrid is the parent of New York State Electric and Gas, which serves 883,000 electricity customers, and Rochester Gas & Electric, which serves 371,000 electricity customers.
The New York Public Service Commission did not respond to a request for comment Monday.
Avangrid also owns Central Maine Power, which has been under fire for poor service.
On Friday, Gov. Janet Mills urged the Maine Public Utilities Commission to “examine Avangrid’s history of equipment purchases in Maine and to ensure that no Maine CMP ratepayer has been or will be harmed.”
“Maine provides to its electric utilities a monopoly and, in return, they owe to Maine people reliable service at just and reasonable rates — nothing less,” Mills said. “Any act of wrongdoing or any misconduct that harms Maine people deserves swift action, accountability and consequences.”
“The allegations made against Avangrid are serious, and we will be reviewing the filings in federal court and following the proceedings closely,” PUC Chairman Phil Bartlett said in a statement Monday to RTO Insider. “As we learn more, we will determine what additional review by the commission may be warranted.”
Avangrid also is the parent of United Illuminating, which provides electricity to 328,000 residential, commercial and industrial customers in the New Haven and Bridgeport areas of Connecticut. The Connecticut Public Utilities Regulatory Authority said Monday it “will monitor the lawsuit and the allegations.”
“During rate proceedings, the authority thoroughly examines the costs proposed by the utilities for recovery to determine prudency,” PURA spokesperson Taren O’Connor said in an email to RTO Insider. “If the authority finds that any utility engaged in the alleged conduct, the associated costs would be disallowed and the authority would consider whether further actions are warranted based on the specific set of circumstances, including, but not limited to, civil penalties, fines and other actions.”
Silva’s attorney, John Griem of Carter Ledyard & Milburn, said, “We don’t have any direct knowledge about” whether Avangrid’s alleged bid rigging affected ratepayers in Connecticut and Maine in addition to New York. “I think a reasonable reader of our complaint could infer that this was a company-wide issue, and that investigation would be warranted,” he said in an interview.
‘Disgruntled Former Subcontractor’
Avangrid’s suit describes Silva as “a disgruntled former subcontractor,” saying he was soured by a $178,000 payment dispute with another Avangrid contractor, Unlimited Technology Inc. (UTI).
It said that Silva threatened to make public his allegations unless the company awarded SLI additional contracts. “When Avangrid refused their extortion attempt, defendants made false, defamatory and malicious public statements designed to harm Avangrid.”
Avangrid said Silva and SLI “continued to solicit work from Avangrid for more than a year after allegedly learning of fraud, corruption and national security issues. Although defendants claimed Avangrid and Iberdrola are a ‘cabal’ with the ‘twisted moral compass’ of Enron, they nonetheless actively sought work from Avangrid as late as five days before these statements to the PRC” in August, Avangrid’s suit says.
Griem called Avangrid’s countersuit “a PR stunt that threatens the rights of all consumers to raise concerns about corporate wrongdoing.”
‘A Mountain of Radically Overpriced Hardware’
Silva’s complaint said that after getting hired by Avangrid in 2018 to improve its cybersecurity program, SLI — “a technology, engineering, architecture and consulting solutions firm” — was blocked from bidding on later projects because the utility steered contracts to companies “willing to participate in a pay-to-play scheme.”
Silva’s suit says Avangrid and Iberdrola (which it called the “utilities defendants”) conspired with the vendors “to procure a mountain of radically overpriced hardware — including scores of routers and multiplexing units that, curiously, they took pains to unpack and install in racks — as if to vaguely suggest that they were configured and operational. Yet those units were never put into service, are quickly growing obsolete and are depreciating by the day.”
The suit named as “vendor defendants” UTI, Black & Veatch (B&V), Madrid-based Prosegur Gestión de Activos and two of its subsidiaries, Cipher Security and Prosegur Security Monitoring Inc.
“SLI made procurements on a straightforward, open-book contract basis, with a fixed margin of 15%, providing no ready channel for the [capital expenditure] inflation the utilities defendants sought,” the suit said. “The utilities defendants thus turned to the vendor defendants, contractors that were wholly aware that the utilities defendants wanted to inflate CAPEX and were happy to assist them in the bid-rigging scheme.”
The suit said Avangrid, Iberdrola and Prosegur allowed the sharing of SLI’s trade secrets and bidding information with competitors. “On numerous occasions, the utilities defendants reissued earlier [requests for proposals] — for which SLI had already submitted best and final offers — to facilitate favored vendors, which would submit new bids styled to incorporate misappropriated SLI business secrets,” it said.
Avangrid and Iberdrola “eschewed competitive bidding, engaged in customer and market allocation, and steered contracts to vendors willing to provide equipment and services that were neither competitively priced nor situationally appropriate (and in some cases unnecessary altogether).”
Silva’s suit describes Prosegur as “a physical security company that would normally engage in the installation of video cameras and provide physical security and monitoring services … [that] has neither particular expertise in hardware and software sourcing nor in design and engineering services. Yet Prosegur entities were repeatedly chosen to bid on contracts requiring large-scale hardware acquisitions they were self-evidently unqualified to undertake and were awarded numerous sole-source contracts for related procurements and personnel.”
Prosegur declined to comment. But Cipher Security COO and CFO Andre Viera Rolim, who was named a defendant in the suit, said in an email: “The company wants to highlight that it is always at the disposal of the authorities and courts of justice to collaborate in everything that is requested. Prosegur always acts with full respect for the rules and current legislation.”
Avangrid allegedly paid excessive prices to Thermo Bond Buildings, which makes communication shelters, substation buildings and modular data centers. | Thermo Bond Buildings
The suit alleges that UTI increased its warehouse three times over the past several years to store “tens of millions of dollars” in unneeded hardware equipment purchased to achieve Avangrid’s quarterly capital expenditure targets.
Among the equipment procured were “tens of millions of dollars of overpriced and/or unnecessary hardware,” including from Thermo Bond Buildings, which makes communication shelters, substation buildings and modular data centers. Other equipment included Nokia, CISCO and Pivot3 equipment “in wildly excessive quantity.” Avangrid also purchased excessive amounts of data storage and unnecessary software systems, SLI said.
UTI did not respond to a request for comment.
Leaked Bid Information
A lawsuit alleges that while working for Avangrid, David Lathrop (left) allegedly leaked confidential bidding information to Unlimited Technology Inc. through UTI executive Charlie Von Stetten. UTI later hired Lathrop as vice president of utilities. | David Lathrop & Charlie Von Stetten via LinkedIn
The suit said Silva learned in 2018 that David Lathrop, Avangrid’s manager of security technical services, conveyed confidential bid information to UTI through Charlie Von Stetten, UTI’s operations director. “Lathrop would habitually leave vendors’ bids open on his desk. On various occasions during that period, Silva witnessed Von Stetten whispering to Lathrop, after which Lathrop would leave his office. During Lathrop’s absence, Von Stetten would take notes on the bids, sometimes even photographing them with his cell phone.”
Silva said that when he raised the issue, “Lathrop smiled and replied, ‘I know nothing; I was in the bathroom.’”
Silva said that as Lathrop was contemplating retirement from Avangrid, he sought a “post-retirement sinecure with an Avangrid vendor.” After Silva said he rebuffed Lathrop, UTI hired him as a vice president of utilities in April 2020.
Before leaving Avangrid, Silva alleged Lathrop “steered” multiple procurements to UTI, including a $15 million contract in 2019 by providing UTI with a copy of SLI’s confidential information.
Silva’s suit refers to UTI as a company that “primarily installs and maintains video cameras to monitor large facilities” that had no experience “in designing or building private cloud data centers or in cloud systems integration.”
But SDM Magazine in October ranked UTI as the No. 7 system integrator in North America for 2021.
On Dec. 2, private equity firm Lee Equity Partners announced it had acquired UTI. Lee did not respond to requests for comment Monday.
Black & Veatch
Silva’s suit also cited a $34 million sole-source contract to B&V, a global engineering, procurement, consulting and construction company, in connection with a “data center convergence project.”
Silva said that two Avangrid executives demanded that Silva share the contents of SLI’s bid on a contract with B&V and that “SLI not seek the outright award of the contract, but instead relegate itself to serving as a subcontractor to B&V.”
“SLI would later learn that B&V — well aware that it was using trade secrets extorted from SLI — used the specifications contained in SLI’s bid in order to improve the B&V bid, and that B&V was ultimately awarded this lucrative, sole-source contract, despite its demonstrably inferior qualifications.”
It also alleged personnel were hired directly through B&V to support a $1.5 billion automated metering infrastructure initiative “at premium hourly rates well in excess of the rates offered by SLI.”
B&V spokesman Jim Suhr denied SLI’s allegations.
“We are aware of this matter, but because this is actively pending litigation, we cannot comment beyond that we believe this suit is meritless and we intend to vigorously defend ourselves against it,” he said.
National Security Threat?
In his first appearance before New Mexico regulators on Aug. 9, Silva alleged that Avangrid introduced “risks to national security” and suggested that Avangrid had hacked the computers of participants in the merger case.
Avangrid said the national security allegation appears to be a reference to one or two incidents, including the expiration of anti-malware software it used. The company said the malware lapsed in early 2020, “which was detected and resolved later that same year. This temporary expiration of anti-malware software was determined to not have any national security impact,” it said.
The second incident concerned a private cloud server containing 150 GB of data that is the subject of a payment dispute between SLI and UTI. Avangrid said SLI is currently maintaining the server, and neither UTI nor Avangrid is willing to take custody of it. “But there is no sensitive data or data affecting national security on that server.”
NERC declined to comment on Silva’s allegation. The Northeast Power Coordinating Council did not respond to a request for comment.
Silva’s attorney Griem said his client made several efforts to tell Avangrid about the problems in maintaining the cybersecurity system he helped to design but was met with “indifference or silence.”
“When you charge ratepayers a tremendous amount of money in order to build a system, and then you don’t properly install it or keep the software updated, given the news around what happened with the [hack of] Continental Pipeline, I certainly think it’s fair to call poorly maintained and hackable infrastructure systems a national security issue.”
Avangrid said Silva also implied that the company is hacking computers, having said, “Anyone attending these proceedings that has spoken against this merger, I strongly urge you as a cybersecurity professional to rebuild all of your computers, change all your passwords, as I have reason to believe that Avangrid is obtaining lots of information through incorrect channels about these proceedings.”
“This statement is also defamatory and false,” Avangrid’s suit said. “It falsely accuses Avangrid of committing a crime in connection with the PRC proceedings.”
DENVER — A Colorado Public Utilities Commission report released last week found that joining an organized wholesale electricity market could save the state’s utilities between $50 million and $230 million annually.
“These kinds of savings were generally found to exist independent of whether Colorado looked west to the CAISO, east to SPP or created something new in the middle working with neighboring utilities,” the report said. It also found that joining a market — whether an energy imbalance market or an RTO — would accelerate the state’s clean energy goals.
The PUC conducted the study in response to 2019’s SB19-236, which directed the commission to investigate Colorado utilities participating in an organized wholesale market and determine whether it is in the public interest by Dec. 1. The PUC also discussed the potential of interstate transmission as a way to more rapidly decarbonize Colorado’s grid earlier this year. (See Colo. Regulators Consider the Advantages of Interstate Tx.)
Colorado is not the only state to have passed legislation requiring its utilities to seek RTO membership. Nevada Gov. Steve Sisolak also signed SB448 in June, and last week he appointed a task force to “capture the ideal conditions and requirements for a future regional transmission organization that will represent the changing economics, resource mix and decarbonization trends of the West,” Vijay Satyal, Western Resource Advocates’ regional energy markets manager, said in a press release.
CAISO or SPP?
As CAISO “already optimizes real-time imbalance energy over 84% of the Western footprint,” it would seem to be the obvious choice, the report said, but the PUC took issue with the ISO’s governance structure, with a concern that states outside of California participating in the market may go unheard.
“The risk exists that CAISO could protect California’s parochial interests at the expense of what is best for the region,” the report said. It pointed to CAISO’s recent filings concerning a wheel-through tariff that “appears to have significantly exacerbated and given substance to these concerns.”
RTO interconnection access queue times | Colorado Public Utilities Commission
Along with governance, the commission is also concerned about CAISO’s resource adequacy issues, which it says have delayed implementation of an extended day-ahead market in its EIM. Until the ISO has addressed this concern, “electric utilities in states like Colorado will likely need to be cautious about shifting control of their transmission assets to a process controlled by California,” the report said.
The report said that joining SPP’s Western Energy Imbalance Service (WEIS) would offer Colorado considerable short-term benefits, including improving dispatch and curtailment issues within the state. Unlike CAISO, WEIS “allows states [to] maintain control over resource planning and acquisition by their electric utilities, which has historically been well run in Colorado, creating considerable customer benefits.”
But even so, WEIS’ governance structure also leaves something to be desired, the report said. It raises concern for new utility entrants because “substantial voting rights [are] vested in individual power marketing agencies and cooperatives, with little opportunity for regulators to meaningfully participate.”
As well as potential governance issues, the report notes the concern of interconnection access and SPP’s overwhelmed queue.
“The inability to fairly and efficiently allocate interconnect to low-cost generators could delay new low-cost clean energy from coming online and would offer no direct mechanism for flowing the benefits through to native load customers,” the report said.
Moving Forward
The report encourages Colorado transmission utilities to communicate with the grid operators to address these concerns and explore potential market options in the meantime. By requiring utilities to join an RTO, Colorado aims to improve interstate transmission in the West to promote resilience and reliability.
“Under these circumstances, one near-term course for Colorado’s transmission utilities may be to participate in an EIM to resolve intrastate dispatch issues and to capture the enhanced near-term coordination benefits but preserve the flexibility to adjust as regional market opportunities in the West evolve,” the report said.
Last week’s Regional Greenhouse Gas Initiative (RGGI) carbon dioxide allowance auction cleared at $13/ton, representing both the highest price and single largest price jump in the program’s history.
There were 53 winning bidders, of which five received one million tons or more, according to the Market Monitor Report for Auction 54. While bids averaged $12.91/ton, the number of bids that were above a 2021 cost containment reserve (CCR) price of $13 exceeded the initial number of allowances offered.
RGGI, therefore, released 3.9 million additional allowances for the auction. Only two previous auctions have released allowances from the CCR, which are allowances held for sale when prices exceed a set amount.
“The 54th RGGI auction marks another successful year of RGGI operations and over $4.7 billion raised to date for the RGGI states to invest in clean energy, energy efficiency and direct consumer benefits,” RGGI Chair and Massachusetts Department of Environmental Protection Commissioner Martin Suuberg said in a statement.
Rising natural gas prices and the potential for Pennsylvania to join the program next year contributed to the clearing price hike, according to a ClearView Energy Partners’ report released Dec. 3.
In October, the Henry Hub gas spot price was higher than it has been in over a decade, reaching $5.51/MMBtu, according to the U.S. Energy Information Administration. It has been steadily rising this year from a low of $2.62/MMBtu in March. Rising gas prices could be improving the economics for coal-fired generation, which ClearView said drives more emission allowances in RGGI states.
EIA data show that coal-fired generation in the 11 RGGI states increased about 33% between September 2020 and September 2021. For that period, auction clearing prices increased from $6.82/ton for 16.1 million allowances to $9.30/ton for 22.9 million allowances.
The latest clearing price, which was 40% higher than the Sept. 8 price, could put Virginia’s new membership at risk and threaten Pennsylvania’s efforts to join RGGI, ClearView said.
RGGI states sold 27 million allowances in the Dec. 1 auction, which raised a total of $351 million. Virginia received $85.6 million, bringing the state’s total since joining the program in January to $227.6 million.
With Republican Glenn Youngkin beating Democrat Terry McAuliffe in last month’s Virginia governor’s race, there is a renewed interest by Republicans to roll back climate policy in the state. That could include pulling Virginia out of RGGI, but ClearView said Democratic control of the state Senate limits that possibility in 2022.
The high clearing price could also hinder Pennsylvania’s prospects for joining RGGI as opponents use it to sway opinions about the effect the program could have on state energy prices. In a Dec. 3 tweet, the Power PA Jobs Alliance, which opposes Pennsylvania’s participation in RGGI, called the auction price “criminal,” claiming it “will devastate poor and senior households.”
A rule that would authorize the state’s participation has received key approvals, but the General Assembly could still pass a resolution opposing the regulation. (See Pa. RGGI Regulations Approved by IRRC.)
ERCOT’s Technical Advisory Committee last week held its last scheduled meeting of a year that was upended by February’s disastrous Winter Storm Uri.
The storm, which came close to collapsing the ERCOT grid, was linked to billions of dollars in damages and hundreds of deaths. It also resulted in political pressure and legislation that revamped the ISO’s board, the regulatory commission, and the market’s design, the latter of which has fallen partly on the stakeholder group to implement.
“What a year it’s been,” said South Texas Electric Cooperative’s Clif Lange, the committee chair, during its Nov. 29 virtual meeting. “We’ve had quite a bit to tackle this year, and we have done some really good work and provided some good information and feedback to the ERCOT board and the commission, as necessary.”
Despite the work, TAC faces uncertainty in its future. In July, interim ERCOT CEO Brad Jones discussed with the committee his plan to convert TAC into an officer-level group. During a candid conversation, Jones told members that if they didn’t “think TAC is in the crosshairs, you’re not paying close attention.” (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)
Since that meeting, Jones’ 60-point roadmap to improving grid reliability has updated his plans to note that TAC “has cancelled further discussion on this item until the new ERCOT Board and/or the [Public Utility Commission] initiate discussions on it.”
Lange told the committee that the board will review TAC’s processes and “make tweaks as necessary, while still retaining valuable input from the stakeholder process.”
“We don’t have any further guidance at this point on what further processes we need to review, but we’ll continue to engage with the board as they deem fit,” Lange told TAC’s members.
Storm-related NPRRs Pass
TAC members approved four nodal protocol revision requests (NPRRs) related to operational actions and other measures taken as a result of the winter storm.
Stakeholders offered some pushback against staff’s urgent measure NPRR1105 allowing ERCOT to instruct transmission and/or distribution service providers (TDSPs) to deploy any available distribution voltage-reduction measures before declaring an energy emergency alert (EEA). The revision is the result of Board Chair Paul Foster’s directive in October that TAC endorse the NPRR before the directors’ December meeting.
“We do think this can be an effective tool in the right circumstances,” Woody Rickerson, the ISO’s vice president of grid planning and operations, said in addressing concerns that the revision will put the system in a weakened condition. “We would like to see this passed so we can use this tool, but we welcome additional conversation on this.”
“It’s a small arrow in the quiver. I think it’s a wasted quiver,” Advanced Power Alliance’s Walter Reid said. “Hopefully, ERCOT will use this in a very judicious way.”
Morgan Stanley Capital Group’s Clayton Greer said he agreed with the NPRR’s use to avoid rolling blackouts but said, “In this instance, we’re not ever close to that level. We’re taking pretty severe action when we don’t even know whether there’ll be [severe] conditions present.”
Morgan Stanley and Demand Control 2 opposed the measure, which passed 23-2 with four abstentions.
A second change (NPRR1107) adds new fees for ERCOT’s weatherization inspections of the resource entity’s capacity divided by the entity’s aggregate capacity. Those inspections already have begun, with staff hoping to inspect about 300 facilities.
The NPRR also clarifies that existing generation interconnection or change request fees apply to all GI projects, regardless of whether they will interconnect at the transmission or distribution level. Those fees are $5,000 for projects less than or equal to 150 MW and $7,000 for projects greater than 150 MW.
Transmission service providers will pay $3,000 for each substation or switching station that is inspected.
“We would like to pay for the actual costs of our plants,” said NRG Energy’s Bill Barnes, who represents Reliant Energy Retail Services. He said lower costs for renewable resources “would be fair.”
The measure passed without opposition, although independent generators Engie North America and Avangrid Renewables abstained.
The committee also approved:
NPRR1103, which establishes the processes for assessing and collecting default charges and default charge escrow deposits for the debt-obligation order securitizing about $800 million owed to the market by cooperatives and municipalities. (See “Securitization Orders Finalized,” Texas PUC Nears Market Redesign’s Finish Line.) ERCOT expects to begin issuing invoices in January.
NPRR1106, codifying the grid operator’s current practice of deploying emergency response service when physical responsive capability falls below 3 GW before declaring an EEA. The PUC ordered the new approach in October.
Staff to Seek Price Correction
ERCOT will request board review and a price correction for eight operating days in September and October after staff discovered a modeling error for a generation transmission constraint in the day-ahead market. Staff patched the defect by the end of surrender, but not before determining the Sept. 30 and Oct. 6-12 operating days met the criteria for a price correction from the board.
Staff’s resettlements of the error resulted in more than $816,000 in increased charges and more than $122,000 in reduced charges to market participants.
The board will take up the issue during its meeting Friday.
Lange Honors John Dumas
TAC is short one member heading into 2022 following the recent death of the Lower Colorado River Authority’s John Dumas in November. Dumas, long a fixture in ERCOT circles and with more than 28 years of experience in managing electric grids and wholesale market operations, was one of four cooperative representatives.
“He was a great person to know. Very congenial and always willing to talk,” Lange said. “He contributed an extraordinary amount to the ERCOT market and the reliability of the system over his career. His influence on the ERCOT region will persist for quite a few years to come.”
Dumas joined LCRA in 2015 as vice president of market operations. Previously, he was with TXU, Vistra’s predecessor, before joining ERCOT in 2008 as manager of operations planning and then director of wholesale market operations.
Annual Membership Meeting Friday
Staff said ERCOT’s annual membership meeting will be held virtually on Friday. In lieu of the usual guest speaker, Jones and Foster will both deliver short comments. The 2022 TAC members, currently comprised of familiar faces, will also be announced during the 30-minute session.
The meeting will follow the board’s December meeting, which will be held in-person in Taylor. The directors will meet in executive session Thursday before holding an open session Friday morning. ERCOT’s Austin headquarters building is closed to meetings during the transition to a new nearby facility.
In-person stakeholder meetings are expected to resume in January, beginning with TAC on Jan. 26. ERCOT’s new headquarters workspace is expected to be ready by then.
TAC Endorses $1.28B Tx Project
TAC’s combination ballot, which passed unanimously, included the endorsement of a $1.28 billion dollar transmission project put forward by the Regional Planning Group. (See ERCOT Finds 345-kV Solution for Valley Constraints.)
The project would add 351 miles of transmission lines radiating from a new substation in the Lower Rio Grande Valley, where ERCOT and the PUC have identified an urgent need for more transmission capacity. The commission in September exerted its new-found regulatory muscle in bypassing the stakeholder process and directing three utilities to add a second 345-kV circuit to an existing transmission line in the valley. (See Texas PUC Directs Tx Construction in Valley.)
The combo ballot also included endorsement of ERCOT’s proposed 2022 ancillary service methodology. Staff recommended one change in computing minimum responsive reserve service (RRS) requirements by using a floor of 2.8 GW to meet the grid’s more conservative operations approach. They also proposed changing the minimum RRS-primary frequency response limit to 1.24 GW, based on NERC’s updated BAL-003 Interconnection Frequency Response Obligation assessment for next year.
The combo ballot also included five NPRRs, two Nodal Operating Guide revisions (NOGRRs), a pair of other binding document changes (OBDRRs), a revision to the Planning Guide (PGRR) and two modifications to the resource registration glossary (RRGRRs).
Members approved separately a revision request (NPRR1109) that allows a resource entity to bring a decommissioned generating unit back to service if it notifies ERCOT within three years of its removal from the network operations model. The measure passed by a 21-2 margin with six abstentions.
NPRR1077: expands NPRR1026’s self-limiting facility concept to include sites with one or more settlement-only generator (SOG) and introduces additional revisions to fully address requirements for generators and energy storage systems (ESSs) connected at distribution voltage. The NPRR requires the SOG’s qualified scheduling entity to provide telemetry of the injection or withdrawal at the point-of-interconnection (POI) for transmission-connected sites or point-of-common coupling for distribution-connected sites.
NPRR1091: addresses energy-price suppression and liquidity issues created by ERCOT’s early and greater procurement of ancillary service by extending the treatment of must-take energy from reliability unit commitments in pricing run to offline non-spinning reserve (non-spin), when it is manually deployed. The change also increases the amount of responsive reserve and non-spin services that an entity can self-arrange above its obligation.
NPRR1094: allows a transmission operator (TO) and a transmission and/or distribution service provider (TDSP) to manually shed load connected to under-frequency relays during an energy emergency alert (EEA) Level 3 if the affected TO can meet its overall under-frequency load shed (UFLS) requirement and its load shed obligation under the Nodal Operating Guide.
NPRR1101: modifies load resources’ deployment grouping requirements if they’re not controllable load resources (“NCLRs”) providing non-spin to include generation resources providing offline non-spin.
NPRR1104: corrects the definition of real-time liability extrapolated (RTLE) to include market activity for entities that have no load or generation but do have real-time exposure.
NOGRR231: updates ERCOT’s regional map in Section 1.1 to reflect the current boundaries.
NOGRR233: allows a TO and a TDSP to manually shed load connected to under-frequency relays during an EEA Level 3 if the affected TO can meet its overall UFLS requirement and load-shed obligation.
OBDRR034: provides ERCOT with the authority to move network operations model resource nodes for POI changes or resource retirements.
OBDRR035: aligns the non-spinning reserve deployment and recall procedure with NPRR1101’s revisions.
PGRR092: allows an interconnecting entity (IE) proposing a SOG to designate it as part of a self-limiting facility during the generator interconnection or modification (GIM) process, consistent with NPRR1077.
RRGRR029: allows an IE proposing a SOG to designate it as part of a self-limiting facility during the GIM process.
RRGRR030: removes voltage levels’ hard coding for certain resource registration information related to transformer data, allowing resources connected to other voltage levels to submit their data without receiving a validation error.
The widespread adoption of clean hydrogen in North America will depend on the construction of “ecosystems” that span economic sectors, state lines and national boundaries, industry supporters said last week at the Green Hydrogen Coalition’s virtual annual conference.
“A green hydrogen economy doesn’t exist in any one city or state; it is a regional and national solution,” Janice Lin, GHC founder and president, said Wednesday.
In wrapping up the two-day conference, Lin said one of her key takeaways was the need for creating hydrogen “hubs” internationally to lay the groundwork for expanded adoption of green hydrogen as a fuel source across multiple economic sectors.
In the U.S., the $1.2 trillion infrastructure bill passed by Congress last month provides $8 billion for development of four such hubs in the country, as well as $1 billion toward domestic production of the electrolyzers needed to produce hydrogen, part of the Department of Energy’s Hydrogen Energy Earthshot initiative. (See Granholm Announces R&D into Green Hydrogen as 1st ‘Energy Earthshot.’)
Sunita Satyapal, director of DOE’s Hydrogen and Fuel Cell Technologies Office, reminded conference participants of the initiative’s “1-1-1” objective: “One dollar for 1 kg of clean hydrogen in one decade.”
Through an effort that predates the infrastructure bill, GHC has been spearheading development of a green hydrogen hub centered in Southern California. The goal of the HyDeal Los Angeles initiative is to deliver green hydrogen for the Los Angeles Basin at $1.50/kg by 2030.
Lin said HyDeal LA was conceived in part to help combat the heavy air pollution that plagues the basin. The top five sources of smog in the region, she said, include ships, heavy-duty trucks, offroad equipment, aircraft and diesel locomotives, and much of that pollution emanates from activity related to the area’s massive ports in Los Angeles, Long Beach and San Pedro Bay.
Green hydrogen could be a “key enabler” for improving the region’s air quality, especially for residents living in the disadvantaged communities near the ports and along L.A.’s busy freeways, she said.
“It’s a scalable, commercially viable alternative, both as a direct fuel as hydrogen [and] as [an] energy ingredient in a synthetic fuel that can directly displace all fossil fuel use in and around the port,” Lin said. “Nearer term, we can use green hydrogen to go after cargo-handling equipment [and] heavy-duty vehicles, and in the medium- to long-term — and we call that 2025 to 2030 — we can use green hydrogen to go after locomotives, oceangoing vessels and harbor craft.”
Despite those objectives, Lin noted that HyDeal LA’s initial foothold into a green hydrogen economy will take shape in the electricity sector, as the Los Angeles Department of Water and Power (LADWP) converts the massive coal-fired Intermountain Power Plant in Delta, Utah, into a natural gas-fired plant capable of burning 30% hydrogen when it opens in 2025. With ample transmission capacity to draw on surplus solar generation, the facility will also be capable of producing hydrogen on site — and able to store large volumes in nearby salt domes.
Intermountain Power Plant in Delta, Utah, which LADWP plans to convert from coal to a gas-fired plant capable of burning a fuel mixture containing green hydrogen. | Green Hydrogen Coalition
LADWP will also replace its gas-fired Scattergood plant in El Segundo, slated for closure by 2024, with a new plant capable of burning a gas-hydrogen fuel mixture. The utility owns other gas-fired facilities that could also be candidates for conversion.
“Repurposing these power plants, and converting them from natural gas to green hydrogen has immediate local air quality and health benefits,” Lin said. “For starters, once power plants are converted to green hydrogen, their emissions are cut to zero for carbon dioxide, carbon monoxide, SOx, volatile organic compounds and particulate matter. In the future, these plants won’t be run as often because we’ll have a whole portfolio of abundant different types of renewable resources, and so the frequency will go down tremendously. That means the NOx emissions from the stack will also go down tremendously.”
European Ambitions
HyDeal LA was inspired by the HyDeal Ambition consortium, a similar and more advanced effort unfolding in Europe. Speaking at the GHC conference, HyDeal Ambition founder Thierry LePercq (also a GHC board member) said the concept was the result of collaboration among industry players and governments.
“But first and foremost, what is fundamental in the HyDeal approach is that you bring upstream companies — that is solar developers and electrolyzer makers; you bring the midstream companies — mostly gas transmission and storage; and then you bring offtakers in industry, in energy and potentially other fields,” he said.
LePercq said that as Germany ramps up its renewable capacity and works to phase out coal (by 2030) and natural gas from an electricity system that has already abandoned nuclear power, all dispatchable power serving the country will need to be “H2-ready.”
“What does that mean? It means that dispatchable power in Germany is going to be based on hydrogen. How many gigawatts of renewable energy [to produce the hydrogen] do you need to get there?” LePercq said.
The hydrogen hub intended to serve those needs will be based in an industrialized area of the northwestern Spanish province of Asturias. The renewables needed to produce the hydrogen will take the form of “captive” — or dedicated — solar resources that will generate low-cost electricity to power the electrolysis process.
LePercq said HyDeal Ambition is approaching its project with the idea of serving demand at scale, rather than serving a limited purpose.
“Because when you are a cement plant or fertilizer plant and steel plant, or a thermal power plant, you want very big volumes. You don’t want a tiny project supplying a tiny bit of hydrogen produced locally at super high prices,” he said. “And I must be frank with you: Until recently, in Europe, most of the projects that have been developed have been developed in what we call ‘policy’ hydrogen, small-scale hydrogen, which is not leaving too much, because small volumes, very high prices, [create a] need for very big subsidies.”
The large scale and ready market will enable green hydrogen to quickly become cost-competitive with natural gas, LePercq explained.
Collaboration Across Sectors, Boundaries
Lin has a similarly expansive vision for the HyDeal LA hub, which would connect the L.A. Basin with the Desert Southwest to include LADWP’s IPP project.
“Long term, we set out to make Los Angeles North America’s first green hydrogen industrial hub at scale, the first to achieve truly 100% renewable electricity affordably and reliably; move to fuel refining and alternative synthetic fuels; provide green hydrogen and its derivatives for shipping [and] aviation [and] maybe someday fertilizer; [and] demonstrate green hydrogen flight,” Lin said.
GHC is also talking with other governments — including Japan’s — about exporting green hydrogen, she said.
“As we look at hydrogen as a whole, we really like the idea of this hub approach, because we really need to maximize the capacity factors of the electrolyzers that we’re installing,” said Peter Sawicki, regional director of sales and marketing at Mitsubishi Power Americas, which will supply the turbines for the IPP project. “And in order to do so, we have to really bring in other sectors, which utilize maybe not as much hydrogen [on a] per-unit basis, but also utilize that hydrogen around the clock.”
Sawicki said LADWP and Mitsubishi are “blessed” with the massive storage capacity available at IPP, but for other regions he likes the idea of using pipelines to store hydrogen or move the fuel to and from storage fields.
“Mitsubishi is not going to be developing these pipelines throughout the United States. We’re looking for really partners on that approach as we look to build out this hydrogen infrastructure as we move forward,” he said.
Michael Healy, vice president of origination at 8minute Solar, said his company thinks the use of behind-the-meter solar is the most cost-effective way to produce clean hydrogen.
“It’s not just as simple as hooking up a solar plant to an electrolyzer. There are all these components that go into it, and it will really drive down costs if they’re integrated together in an efficient and optimal way,” Healy said.
Andrew Hegewald, Utah-based gas development manager for Dominion Energy, said four elements need to be addressed in building a hydrogen ecosystem: production, transportation, distribution and consumption. Furthermore, each sector, such as transportation or power generation, will require its own ecosystem.
“Once you understand the landscape, then it’s figuring out who would the partners be in building this ecosystem,” he said.
Barbra Korol, executive director of Alberta’s Department of Energy, noted that the Canadian province currently produces the equivalent of 24% of all hydrogen generated in the U.S., most of which is “gray” hydrogen produced from natural gas.
“Our ambition is to transition that gray production to blue hydrogen or ultra-low carbon — clean — hydrogen,” Korol said.
Alberta has an abundance of natural gas for producing hydrogen, but the province is open to “other pathways,” recognizing that its competitiveness will require reducing the carbon intensity of its hydrogen, she said. The province’s hydrogen strategy, released last month, calls for clean hydrogen “integrated at scale” for use in domestic and export markets.
“It’s very much a regional strategy that seeks to collaborate and find synergies with our partner to the west — our friends in British Columbia — as well as our friends to the south.”
“We feel there’s great alignment between the provinces, the [Canadian] federal government and our friends in the U.S., with each region holding different strengths and advantages, and that collaboration and partnership can address those challenges, resolve the gaps within the supply chain, and really advance this economy swiftly and with purpose,” Korol said.
PJM stakeholders received an update on Transource Energy’s suspended Independence Energy Connection (IEC) transmission project at last week’s Transmission Expansion Advisory Committee meeting.
Nick Dumitriu, principal engineer in PJM’s market simulation department, provided an update on the 2020/21 long-term market efficiency window, highlighting the suspended project in Maryland and Pennsylvania.
The Pennsylvania Public Utility Commission voted 4-0 in May to reject a series of related applications and petitions filed by Transource for lines in Franklin and York counties. The PUC denied the project based on concerns about whether the need established in the PJM planning process met the requirement for needs specific to Pennsylvania. (See Transource Tx Project Rejected by Pa. PUC.)
The PJM Board of Managers endorsed the RTO’s recommendation to suspend the IEC project at its Sept. 22 meeting because of the “permitting risks” and to remove it from the pending Regional Transmission Expansion Plan models.
Dumitriu said PJM is required by schedule 6 of the Operating Agreement to “annually review the cost and benefits” of board-approved market efficiency projects that meet certain criteria to assure that a project continues to be cost beneficial. The annual re-evaluation is not required for projects that have started construction or have received state siting approval, and the Transource IEC was the only eligible project for 2021 re-evaluation.
Dumitriu said the base case analysis conducted by PJM yielded a benefit-to-cost ratio of 1.44, which excluded $131.88 million in sunk costs of incurred spending on the project. Dumitriu said that when the full in-service cost of $428.76 million for the project was analyzed, the benefit-to-cost ratio was 1.
The re-evaluation using a sensitivity scenario with higher load growth in PJM yielded a benefit-cost ratio of 2.08 with the exclusion of sunk costs and 1.44 for the full in-service cost.
A sensitivity scenario using additional coal retirements in the RTO yielded a benefit-cost ratio of 2 with the exclusion of sunk costs and 1.39 for the full in-service cost. Dumitriu said Talen Energy announced that its Montour generation facility in Pennsylvania and the Brandon Shores and H.A. Wagner coal generation facilities in Maryland, totaling more than 3,500 MW of generation, will cease coal-fired operations by the end of 2025 as the company moves toward renewable energy and battery storage projects.
Dumitriu was asked if PJM saw congestion growing on the AP South interface after removing the Transource IEC project. He said there are changes in congestion patterns after removing the IEC and that PJM sees “increasing congestion” on all the nearby constraints.
NJ OSW Projects
Work continues on proposals to interconnect New Jersey’s offshore wind projects through the 2021 state agreement approach window. Aaron Berner, PJM senior manager, provided an update on the 2021 RTEP analysis.
Berner said the proposals, which were presented at the October TEAC meeting, have been posted on PJM’s competitive planning page in redacted form. (See “NJ OSW Proposals,” PJM PC/TEAC Briefs: Oct. 5, 2021.)
New Jersey is preparing to be a manufacturing and operational hub for wind projects up and down the East Coast. | AWEA
PJM is continuing to work through various analyses as part of the option 1a portion of the OSW window, Berner said, which included onshore upgrades on existing facilities. A total of 45 proposals were submitted for option 1a.
The RTO is working with entities who submitted proposals to identify issues in the planning process, Berner said, while also utilizing consultants as part of the competitive process to begin evaluations of construction processes and financial terms for the proposals.
Berner said PJM is concentrating on starting evaluations for 26 proposals that call for new offshore transmission connection facilities and eight proposals looking at offshore transmission networks. Berner said offshore transmission is more complicated because they’re not “traditional” facilities PJM has experience with building.
PJM is working toward adopting the schedule provided in the NJBPU guidance document indicating certain processes to be employed going forward during the project evaluations. New Jersey retains the right to elect to move ahead with any of the projects and is targeting the end of 2022 to make final decisions.
Berner said many of the proposals will be adjustable for changes in “scheduling accommodations” and the megawatt injection quantities based on NJBPU needs.
The BPU has already awarded three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2 projects, both developed by Ørsted, and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years to help the state reach its goal of supplying 7,500 MW of offshore wind by 2035. (See NJ Awards Two Offshore Wind Projects.)
Generation Deactivation Notification
Phil Yum of PJM provided an update on recent generation deactivation notifications.
Yum said PJM received two battery deactivation requests in the ComEd transmission zone, including the Joliet Energy Storage battery and the West Chicago Energy Storage battery, which are both six years old.
Generation deactivation announcements in PJM from 2018-present | PJM
Each battery unit has 20-MW capabilities for the energy portion, Yum said, but they were listed as 0 MW for capacity.
The requested deactivation date for both units is Feb. 8, and a reliability analysis is underway.
Stakeholders endorsed a joint PJM/Independent Market Monitor proposal regarding fuel-cost policy standards at last week’s Market Implementation Committee meeting.
The proposal, which was developed at the Cost Development Subcommittee, received 221 votes in favor (95%) and won 192 votes (95%) favoring it over the status quo.
PJM’s fuel cost policy form. | PJM
Melissa Pilong, senior analyst in PJM’s performance compliance department, reviewed the proposal clarifying fuel-cost policy standards in Manual 15 and Operating Agreement Schedule 2 penalty language. The proposal was first presented at last month’s MIC meeting. (See “Fuel-cost Policy Standards and Penalties,” PJM MIC Briefs: Nov. 3, 2021.)
Pilong said the proposal includes a combination of clarifications and language for more elaboration on PJM’s fuel-cost policies resulting from the RTO’s examination of the fallout from the February winter storm in Texas and other parts of the South and Midwest.
It would have market sellers of generation units verifying that all intraday offer triggers are specified in the unit’s fuel-cost policy. Market sellers will also have to verify that weekend or holiday natural gas estimation practices match either the default assumptions in the PJM Fuel Cost Policy Guidelines contained in Manual 15 or specify estimation practices in the unit’s policy.
“This takes the burden off the market seller to have to update their fuel-cost policy to clarify what their estimation practice is,” Pilong said.
The Manual 15 updates include changes to the intraday update triggers. Pilong said market sellers need to have a one-time trigger to update the maximum allowable cost offer to opt into intraday offers.
Paul Sotkiewicz of E-Cubed Policy Associates said he wished the issue would have been discussed in a different venue, calling attendance of the Cost Development Subcommittee “spotty at best.” Sotkiewicz said most stakeholders don’t have the ability to attend all PJM meetings, and many of the issues discussed at the CDS are “extremely down in the weeds and esoteric.”
Sotkiewicz requested that PJM find a way to bring some of the issues discussed at groups like the CDS to the MIC for broader discussions before they’re voted on.
“These are potentially pretty substantial changes that are happening that affect all generation owners,” Sotkiewicz said.
PJM will seek final endorsement of the proposal at the Members Committee in February and issue a FERC filing following approval by the Board of Managers.
Virtual Combined Cycles Regulation Endorsed
A proposal from Vistra addressing regulation for virtual combined cycles received unanimous stakeholder support in an acclamation vote.
Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the proposal to revise Manual 12. The issue charge was originally endorsed at the May MIC meeting and worked on during committee meetings. (See “Virtual Combined Cycle Regulation Issue Charge Endorsed,” PJM MIC Briefs: May 13, 2021.)
Olaleye said units that are modeled virtually by PJM can sometimes receive varying regulation awards from the market clearing engine, which Vistra has been experiencing with some of its units. When a combined cycle unit is modeled as multiple virtual units, there is a possibility for unbalanced or unequal regulation awards to each unit by the engine.
Vistra’s proposed enhancement to performance group scoring calls for calculating the “hourly” score and extending it to each market resource with an assigned regulation for the given hour. It also called for PJM to calculate the “historic” performance score and extend it to each market resource in the performance group.
Olaleye said the enhancements would ensure that all resources of the performance group have the same historic performance score, which should fix the regulation clearing calculation problem in the software.
Becky Robinson of Vistra said the proposal should solve the identified problem that only impacts a “handful” of market participants while having “no negative effects” for other market participants not impacted by the regulation for virtual combined cycle units.
Capacity Offer Opportunities
Jason Barker of Exelon provided a first read of a problem statement and issue charge in conjunction with Brookfield Renewable to address the treatment of generation with co-located load and to examine capacity offer opportunities.
Barker said there’s a “burgeoning consumer interest” in co-locating new, large interruptible commercial loads behind the wholesale meter of existing generation resources. He said interested customers include those engaging in commercial activities like Bitcoin mining, server farms and hydrogen electrolysis that require “very fast” curtailment times of 10 minutes or less in their facilities.
“This is a discreet and novel issue due to the characteristics of the load,” Barker said.
Customers are expressing preferences for a low-cost physical energy supply, Barker said, while others are seeking a carbon-free physical energy supply.
Barker said PJM’s current market rules make customer choices “challenging,” resulting in “unduly costly and inefficient outcomes for the grid.” He said PJM markets don’t offer options for fast-response interruptible customers to select physical supply from their choice of generator technology.
The issue charge includes investigating clarifications and market rule changes to support new interconnection configurations for highly interruptible load that is co-located with generation. Key work activities cited include education regarding current capacity offer requirements for existing generation resources and interconnection requirements for “new, large, fast-response interruptible commercial load.”
The expected deliverables in the issue charge are potential modifications to capacity market rules in the PJM tariff and relevant manuals and potential modifications to cost-based offer rules.
Work on the issue is expected to take six months at the MIC.
Consultant Roy Shanker said he believes state rules on the retail side will be relevant to the discussion, suggesting that the key work activities include education on how the modifications will interact on the retail side.
“There are lots of interesting rules and laws that may or may not apply to these kinds of arrangements based on state franchise laws,” Shanker said.
Erik Heinle of the D.C. Office of the People’s Counsel said he would like to see education included about how other RTOs and ISOs are handing the issue of generation with co-located load.
Monitor Joe Bowring said the key work activities listed in the issue charge “make sense,” but he was a “bit skeptical” about how the issue is laid out for discussion. Bowring said the language can be interpreted as providing capacity value to the behind-the-meter customer but requiring other customers to pay for it.
Bowring suggested the issue charge should be revised to be more neutral but that it remains an important topic to discuss.
“It’s fundamentally about how the costs are getting assigned and who’s winning and who’s losing as a result,” Bowring said. “This is a potentially radical change to the capacity market design.”
The committee will be asked to approve the issue charge at the January MIC meeting.
Minimum Run Time Guidance
Tom Hauske, principal engineer in PJM’s performance compliance department, provided education and a first read of a problem statement and issue charge addressing pseudo-modeled combined cycle minimum run time guidance.
Hauske said PJM and the Monitor were bringing the issue forward as a result of the “disaggregation of many multiple block combined cycles” into individual pseudo-model market units, or virtual modeled combined cycle units. Market sellers can currently model a combined cycle unit as multiple pseudo units composed of a single combustion turbine and a portion of a steam turbine.
Hauske said if the market units of a pseudo-modeled unit are dispatched at different times on parameter-limited schedules, the potential exists for one or more of the pseudo-modeled units to operate “for some period beyond the minimum run time parameter limit for an identical non-pseudo-modeled combined cycle unit.”
The issue charge includes a key work activity of stakeholders developing guidance for market sellers regarding offering operating parameters for pseudo-modeled combined cycle units through education on the issue. Expected deliverables include revisions to Manual 11 or other relevant PJM governing documents.
Hauske said PJM was looking to use the “CBIR Lite” (Consensus Based Issue Resolution) process in Manual 34 to develop any manual changes and have final endorsements of any changes by the Markets and Reliability Committee’s meeting March 23.
Calpine’s David “Scarp” Scarpignato said the issue was a “little bit complex” to use the CBIR Lite process and that it would be better to conduct discussions under the normal CBIR process. Scarp said he prefers to use the normal CBIR process in stakeholder discussions “unless there’s a real reason to deviate from them.”
“I don’t see a burning reason to go to the lite process here,” Scarp said.
Hauske said the shorter process was suggested because PJM’s unit-specific parameter adjustment process starts on Feb. 28 with market sellers submitting requests. PJM must provide a determination on the requests by April 15.
Scarp said he “doesn’t see a huge reliability” threat if the issue isn’t resolved in time and didn’t want to rush discussions to get imperfect language implemented. He said the prior rules were used last year, and there were no major reliability concerns.
“I definitely want to get the work done, but I want to get it done in due diligence and a conscientious fashion,” Scarp said.
De-energized Bus Replacement
Vijay Shah, lead engineer in PJM’s real-time market operations department, provided a first read of conforming revisions to Manual 11: Energy and Ancillary Services Market Operations as part of five-minute dispatch and pricing. The changes are designed to address enhancements to the dead bus replacement logic for assigning prices to de-energized pricing nodes (pnodes).
Shah said the objective of the revisions are to provide increased transparency in the logic and how it performs replacements for de-energized buses. PJM is required to produce LMPs for all pnodes in the RTO’s network model for all intervals, including de-energized pnodes.
Shah said PJM wants to use new logic based on Dijkstra’s algorithm, an industry standard, to find a suitable replacement for de-energized pnodes. He said the algorithm uses the “least impedance path” to find a suitable source, and it’s to be implemented in both day-ahead and real-time market clearing engines.
The manual changes include updated language to reflect the new logic.
The committee will be asked to endorse the manual revisions at the MIC’s meeting Jan. 12, with final endorsement at the Jan. 26 MRC meeting. The new dead bus replacement logic would be effective March 1.
Manual 6 Revisions Endorsed
Members unanimously endorsed conforming changes to Manual 6 resulting from the endorsement of a proposal to address PJM’s auction revenue rights and financial transmission rights at the October MRC meeting. (See Stakeholders Endorse PJM ARR/FTR Market Changes.) Emmy Messina, senior engineer with the PJM market simulation department, first presented the manual changes at the November MIC meeting. (See “Manual 6 Revisions,” PJM MIC Briefs: Nov. 3, 2021.)
Messina said the changes would only impact Manual 6 and include language for bid limits and the network model user guide. The changes would update section 6.6 to reflect an increase of bid limits from 10,000 to 15,000 per corporate entity, auction round and period in FTR auctions. The February 2022 auction will be the first FTR auction with the updated limits.
Section 9.1 was also updated to direct stakeholders to a new network model user guide on the FTR section of the PJM website to get additional information on the auction.
PJM will now seek endorsement of the manual changes at the December MRC meeting.
FERC last week settled a pair of disputes over waivers from SPP’s generator interconnection procedures (GIP), approving one and denying the other.
The commission reaffirmed Lookout Solar Park’s request for a limited waiver of the GIP’s financial security cure period and posting requirements in responding to SPP’s rehearing request (ER21-1841). However, the agency also denied Invenergy’s request for a prospective waiver from GIP security posting requirements (ER21-2807).
In the first Dec. 1 order, FERC found that the waiver request it granted Lookout Solar earlier this year satisfied the commission’s criteria for granting waivers in that the request did not harm third parties or have undesirable consequences. It clarified that the waiver order extended Lookout Solar’s timeline to either make the applicable financial security payments or withdraw from the generator interconnection queue.
Lookout Solar is developing a 110-MW solar facility in South Dakota and entered the SPP GI queue in 2017. It said in its waiver request that the grid operator posted the results of its definitive interconnection system impact study (DISIS) queue cluster on Oct. 30, 2020, but then reposted revised results on Nov. 20, 2020, triggering a requirement that Lookout Solar post about $16.9 million in financial security.
The proposed Lookout Solar Park in South Dakota. | WAPA
The developer disputed the revised obligation and said it had reached an agreement via email with SPP that further modified the obligation to $8.1 million. The RTO posted additional study results in April allocating Lookout Solar $181.6 million in upgrades and requiring $28.1 million in financial security. SPP subsequently notified the cluster’s customers that it had identified errors in the DISIS and extended the cluster’s next decision point until May 13.
The solar developer contended that SPP acknowledged that the study “appeared” to over-allocate certain upgrade costs to the facility. It said the RTO did not revise the reposted study results and ultimately told Lookout Solar that no substantive corrections were required.
SPP withdrew Lookout Solar from the queue and asked that it post its financial security amounts to restore its position, leading the developer to file its waiver request. FERC granted the request over SPP’s objections.
Commissioner James Danly concurred separately with the order but expressed his “continuing concern” over the “innumerable” waiver requests FERC grants and reiterated that the commission “must be sparing in its liberality.”
Invenergy Issue not ‘Concrete’
The commission found that Invenergy did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver” in the second order.
The renewable developer said it had eight interconnection requests pending in the same DISIS queue cluster as Lookout Solar. It alleged that SPP said the DISIS study would need to be redone because higher-queued requests were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.
Invenergy said that faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.
FERC said Invenergy did not show that its potential loss of its posted financial security was a concrete problem warranting a waiver from SPP’s tariff. It said there was not sufficient detail to demonstrate that an IC customer having to make decisions and provide financial security based on information it views as unsatisfactory warrants granting the waiver.
The commission also said Invenergy’s waiver request is distinguishable from Lookout Solar’s request in that the agency relied on undisputed allegations in the record of SPP’s inconsistent communications and actions.
Commissioner Mark Christie dissented from both orders, saying that after reading the Lookout Solar rehearing order, he could “reach no conclusion other than that today’s [second] order unduly discriminates against Invenergy in an unlawful manner.”
He said there is no “rational basis” for distinguishing between Invenergy and Lookout Solar and said the decision to deny Invenergy’s waiver on “thin factual differences is mystifying.”
“Today the commission relies on semantics to get itself out of the mess it inevitably made by granting the initial waiver in Lookout Solar — the result of which is to put Invenergy (and presumably any subsequent waiver applicants in the cluster) at a patently discriminatory commercial disadvantage to another member of the queue without any rational basis to distinguish the two waiver requests,” Christie wrote.
