More than 50 electric utilities across the U.S. announced the creation of a national coalition Tuesday to facilitate the buildout of fast-charging stations on major highways in most states, giving electric vehicle owners the ability to travel distances by the end of 2023 without range anxiety.
The Edison Electric Institute “and our member companies are leading the clean energy transformation, and electric transportation is key to reducing carbon emissions across our economy,” EEI President Tom Kuhn said in a statement. “With the formation of the National Electric Highway Coalition, we are committed to investing in and providing the charging infrastructure necessary to facilitate electric vehicle growth and to helping alleviate any remaining customer range anxiety.”
The coalition is expected to focus initially on the nation’s interstate system.
The U.S. Department of Energy estimates there are currently about 6,800 fast-charging stationsin the country and nearly 47,000 slower public charging stations. A DC fast charger can repower the batteries of many new EVs to 80% in 20 to 30 minutes, according to ChargePoint, a California-based EV infrastructure company. Older hybrid EVs may not be equipped to take the high voltage of a fast charger.
The $1.2 trillion Infrastructure Investment and Job Act, which President Biden signed Nov. 15, allocated $7.5 billion for alternative fuels, including a buildout of a national EV charging network.
EEI estimates that member utilities have already spent more than $3 billion on “customer programs and projects to deploy charging infrastructure and to accelerate electric transportation.” As of February, 31 states and D.C. had approved electric transportation filings made by 52 companies, EEI previously reported.
The organization estimates there are about 2 million EVs on the road today, less than 1/10 of the 22 million expected by 2030. It has estimated that EV drivers will spend the equivalent of about $1.20/gallon, based on average U.S. residential rates.
Merchant generators joined ISO-NE’s Internal Market Monitor on Tuesday in warning that the RTO’s proposal to eliminate the minimum offer price rule (MOPR) will suppress prices.
Other stakeholders debated whether the implementation of the RTO’s plan should be delayed until it approves long-term market rule changes on capacity accreditation and reserves.
The NEPOOL Markets Committee is scheduled to vote on the RTO’s proposal at its first meeting next year, Jan. 11-12. Stakeholders interested in proposing amendments should notify the committee secretary by Jan. 3 for inclusion on the agenda.
The RTO’s proposal was prompted by calls by FERC Chair Richard Glick and Commissioner Allison Clements to abolish the MOPR, which they said were undermining state decarbonization efforts. (See ‘Good Riddance’ to Old PJM MOPR, Glick Says.)
The IMM’s David Naughton and Michael Redlinger outlined their concerns with the RTO’s proposal at a daylong MC meeting, acknowledging that the MOPR prevents some state-sponsored renewables resources from clearing the Forward Capacity Market (FCM), undermining decarbonization efforts and causing “over-procurement.”
But they said the rule has been effective at limiting the impact of below-cost offers on the capacity market. “Inadequate mitigation rules may undermine the efficiency of the FCM in performing its function and ability to produce just and reasonable rates,” they said in a presentation.
They also acknowledged that efforts to address the tension between price formation and states’ generation preferences — such as the renewable technology resource (RTR) exemption and substitution auction under the Competitive Auctions with Sponsored Policy Resources (CASPR) — “have had limited results.”
But they said the RTO should be pursuing long-term market changes that could help, saying “net carbon pricing” could reduce the “missing money” for low-carbon generation while being compatible with the current broad MOPR.
Allowing sponsored resources to clear the auction “leads to essentially walking down the FCA [Forward Capacity Auction] demand curve,” they said. “MOPR elimination will allow [subsidized] resources to offer at a lower cost than they otherwise would absent the subsidy, in many cases down to $0.”
The price suppression and volatility could result in premature retirements and lead investors to demand higher returns on investment, shorter pay-back periods or long-term contracts, they said.
ISO-NE’s proposed buyer-side mitigation (BSM) rules would exempt subsidized resources, resources of 5 MW and less, energy efficiency, and projects whose sponsors self-certify they have no load obligations that could benefit.
The Monitor said the BSM rules would focus on uneconomic conduct that impacts prices for the benefit of a “net” or “leveraged” position. Project sponsors would have the option to demonstrate that there is no incentive — no net financial benefit — to exercise buyer-side market power.
“But the exercise of market power can take many forms, and the IMM is focused on the impact on price formation from below-cost offers regardless of whether to benefit a load position,” it said. “Mitigation needs to address market power in whatever form when it would impair competitive market outcomes.”
The Monitor said the focus on sponsors’ lack of incentive to suppress prices would allow the sponsors to decide what information to provide to the monitors.
“This limits the IMM’s ability to evaluate and determine whether the declaration of no material net benefit is accurate and hence the lack of mitigation warranted,” it said. Current rules, it noted, require market participants to provide “all” relevant information.
Merchants Share IMM Concerns
Bruce Anderson, of the New England Power Generators Association (NEPGA), said his group shares the Monitor’s concerns.
“The conditions under which the FCA would need to clear to produce just and reasonable rates … appear to create significantly increased risks to either reliability, market efficiency (reliability-must-run agreements) or perhaps to both,” NEPGA said. “Alternatively, those risks do not materially increase, but the market produces unjust and unreasonable rates.”
NEPGA said the RTO should not eliminate the MOPR until it implements long-term rule changes such as effective load-carrying capability (ELCC) and wholesale market designs that compensate resources for reliability services the RTO doesn’t pay for now. “These necessary market reforms would provide some measure of balance in a proposal that at present fails to balance consumer and investor interests,” Anderson said.
Anderson questioned why the RTO is pushing the MOPR elimination given that FERC has not issued an order requiring such action. “The proposal attempts to satisfy a mandate and deadline that does not exist,” he said.
Andrew Weinstein of Vistra (NYSE:VST) took a similar position. Vistra proposed a transition, which Weinstein said “buys time for long-term durable solutions to better align with complete MOPR elimination.”
Long-term solutions such as ELCC or a reserves product “cannot be achieved in the timeline set forth by ISO-NE,” he said. ISO-NE’s proposal, he said, could create “market risks that will remain unresolved until long-term designs can be approved.”
Vistra called for a two-year transition period for FCAs 17 and 18, with the MOPR eliminated for FCA 19.
The rule would remain in place with an RTR exemption of 300 MW for FCA 17 and 400 MW for FCA 18. Between 229 and 292 MW of sponsored resources cleared in FCAs 13 to 15. There would be no weighted average cost of capital adder while the MOPR is intact, and the net cost of new entry (CONE) would also remain unchanged until FCA 19.
Weinstein noted that the RTO has embraced several out-of-market designs to address reliability issues over the past decade, yet it has conducted no study of how removing MOPR would impact the ability to serve load.
“Given the reliability risks and legal and policy risks of immediate and complete MOPR elimination, regional consensus on a long-term durable solution is strongly preferable,” he said.
Enviros: No Need for Transition
The Natural Resources Defense Council and Conservation Law Foundation, however, said no transition is warranted. Because the region is currently oversupplied, they said, it has sufficient time to address the long-term market changes.
“We know where the region is headed, and new entry from state clean energy resources is known well in advance,” NRDC’s Bruce Ho said in a presentation. He said the failure of the CASPR initiative to integrate state clean energy resources “has already led to unnecessary delays and consumer costs.
“Delaying MOPR elimination could result in [an] FCM that fails to incorporate clean energy through the end of this decade,” he added.
While the groups said they support ISO-NE’s approach to removing the MOPR, they questioned the RTO’s proposal to adjust CONE financial inputs, noting that the normal CONE/net CONE cycle allows consideration of multiple market and rule changes.
“Tariff, policy and market changes happen every year, and we have never adjusted CONE between cycles to address them,” Ho said. “What makes this change so different?”
LS Power Responds to ISO-NE Criticism
LS Power used its time to defend its proposed Scarcity Event Reduction Framework (SERF), which it said would provide “incremental incentives” for investing in flexibility and reliability in time for FCA 17.
The construct would credit or charge resources for their energy and reserves supplied when real-time reserve prices are positive.
The proposal is based on the current Pay-for-Performance (PfP) design but would increase the instances in which performance is assessed. While PFP design assesses performance only when there is a capacity scarcity condition (CSC) — triggered by a shortage of a minimum real-time reserve requirement — SERF would apply the new credits and charges whenever there is a positive real-time price for reserves but no CSC.
LS Power’s Mark Spencer said changes are needed to restore the balance between buyers and sellers because “there is no tangible risk of a scarcity event, and the adverse selection problem raised in the 2014 PfP filing has yet to be addressed.”
He noted there has been only one event — lasting about 2.5 hours — in the last four summers, although the RTO predicted a handful of hours in every year. In the last five years, 7 to 9 GW of capacity resources that obtained a capacity supply obligation in the FCA — more than 20% of the total on average — did not participate in the peak load hour.
LS Power wants ISO-NE to go beyond eliminating the minimum offer price rule (MOPR) and embrace broader proposals to incentivize generator performance. In the last five years, 7 to 9 GW of capacity resources that obtained a capacity supply obligation — more than 20% of the total on average — did not participate in the peak load hour, it said. | LS Power
Eliminating the MOPR will “further reduce the already miniscule probability of scarcity events,” he said.
Spencer said the proposal was an effort to address “a market in distress that requires immediate attention.” Market design efforts the RTO has in its work plan such as ELCC and day-ahead co-optimization “will not materially improve this situation,” he said.
In a Dec. 3 memo, ISO-NE said it opposed the proposal because it would incentivize resource owners to offer in the real-time energy market at prices below their marginal cost and ignore dispatch instructions.
Spencer said the RTO’s concern that some resources would offer below their cost when it anticipates a SERF event to avoid penalties is not realistic because it would require “perfect foresight” to make the strategy profitable. A resource would have to predict a SERF event at least 30 minutes in advance.
LS Power said SERF events would usually be less than one hour and may be spread over two delivery hours, while real‐time reoffers are binding for an entire delivery hour. “Frequently part of the hour would be unprofitable, offsetting the profit‐making potential in the rest of the hour.”
SERF events would occur infrequently — only 13 days, or 7.6% of the summer peak days — during the last two years.
“The ISO’s analysis … ignores the cost of those days when the generator submits a below-cost offer but a SERF event doesn’t occur,” Spencer said.
MC Vice Chair, Committee Secretaries
Also Tuesday, the committee re-elected Sigma Consultants’ William Fowler as vice chair. No other members expressed an interest in the position, the RTO said.
Earlier this week, ISO-NE announced committee secretaries for 2022:
Dennis Cakert, who recently joined the RTO as a lead analyst in the NEPOOL Relations team, will serve as secretary to the MC. He previously was the senior manager of regulatory affairs and state policy with the National Hydropower Association (NHA).
Marc Lyons, who has served as the Reliability Committee secretary for 12 years, will become secretary for the Transmission Committee.
Nicholas Gangi. who recently joined the RTO as a lead analyst in the NEPOOL Relations team after working as an engineer with Eversource Energy, will be secretary of the Reliability Committee.
New York officials on Monday tweaked the state’s draft scoping plan on climate action to include cost/benefit and consumer impacts analyses as soon as possible.
Donna L. DeCarolis, National Fuel Gas Distribution | NYDPS
“To wait until after implementation to assess impact seems too late,” Donna L. DeCarolis, president of the National Fuel Gas Distribution Corp., told the state’s Climate Action Council.
The CAC will meet Dec. 20 to vote on a final draft scoping plan for achieving the goals laid out in the Climate Leadership and Community Protection Act; the plan will be discussed over the course of 2022 before implementation the following year. Monday’s meeting was an ad hoc extension of a Nov. 30 session that ran out of time. (See NY Predicts 200K+ New Clean Energy Jobs by 2030.)
Several council members asked that energy affordability and consumer pricing impacts be included within the draft scoping plan, but the integration analysis that provides the overall economy-wide costs doesn’t actually get to the ratepayer impacts, said Sarah Osgood, executive director of the council.
“In order for us to get to the ratepayer impacts you need to have specific details on a policy, and since we’re not at that level of detail staff is recommending that specific ratepayer costs would be identified as part of a subsequent implementation process,” Osgood said.
Lack of Data?
The council was asking for feedback in relation to a proposed resolution essentially saying that it cannot at this point in time include ratepayer cost impacts of every particular policy that’s included in the scoping plan, Osgood said.
Sarah Osgood, NYCAC | NYDPS
Known costs certainly could be articulated in the draft scoping plan, said Gavin Donohue, president and CEO of the Independent Power Producers of New York.
“There are recommendations where I would readily admit that we maybe don’t know the cost today, but where we have recommendations that the NYSERDA [New York State Energy Research and Development Authority] or the Public Service Commission can determine the actual customer cost, I think that should be analyzed to be part of a scoping plan,” Donohue said. “Without that I think it’s a real incomplete report and a disservice to the public.”
Much robust cost and impact analysis is happening in New York, but the council should push for better coordination between state agencies to gain macro efficiencies, said Raya Salter of NY Renews.
IPPNY CEO Gavin Donohue | NYDPS
The PSC can look into affordability and macro efficiencies that can be captured, but it’s a challenge to fit these critical pieces into the plan correctly in the next week or so, Salter said. The process would also be helped by the council getting an update from the Climate Justice Working Group on the definition of what constitutes a disadvantaged community, she added.
Osgood agreed to put that update on the Dec. 20 agenda.
“We have not yet resolved the question of who would ultimately pay for some of these initiatives and or policies,” council Co-chair and NYSERDA CEO Doreen Harris said. “We not only have to analyze the costs themselves, but also the question of who is paying is a related challenge.”
A compromise could be that when the council’s work reaches the point of a specific regulatory proposal, it recommends that there has to be a specific ratepayer assessment at that time, said Anne Reynolds, director of the Alliance for Clean Energy New York.
Calculating Benefits
Several council members reminded their colleagues that cost/benefit analysis included the word “benefit,” and that sometimes the benefits will outweigh the costs.
LIPA CEO Thomas Falcone | NYDPS
For example, installing air-sourced heat pumps will drive customer electric bills up because they’re using more electricity, but their heating bill will go down, said Thomas Falcone, CEO of the Long Island Power Authority.
“At least on Long Island, even at today’s natural gas prices and oil prices, there’s a huge benefit to moving to electrification,” Falcone said. “About 40% of Long Island customers use oil heat, and if you move those oil heat customers to an air-source heat pump, it saves them a ton of money.”
Total energy use goes down rapidly with heat pumps, and that’s why the emissions are going down, said Robert Howarth, professor of ecology and environmental biology at Cornell University.
“I just want to highlight that because it’s exactly the same case that beneficial electrification applies equally in the heating sector and in the transportation sector,” Howarth said.
PJM is looking to create guidance and requirement language for several manuals related to the implementation of a dynamic line rating (DLR) system in the RTO.
Chris Callaghan, senior business solution engineer with PJM’s applied innovation department, presented a first read of a problem statement and issue charge at last week’s Operating Committee meeting.
Transmission lines are typically operated using a static rating calculated for periods of time using near worst-case values for predicted weather conditions, but DLRs can be calculated in real time and show the resulting weather and other environmental impacts to the line ratings.
Callaghan said DLR deployments in PJM will involve the installation of a data collection sensor on or near an existing transmission line to collect real-time conductor temperature information. The sensor technologies that will be deployed in PJM include weather stations, electromagnetic field detectors and thermal cameras.
While different sensor technologies exist, Callaghan said, PJM wants to see the DLR installation projects have a common goal of targeting congested transmission facilities where the conductor is the most limiting element.
PJM has identified several manuals that may require new language for the incorporation of DLRs. The updates include section 2 of Manual 1 related to member control center requirements, section 2 of Manual 3 on thermal operating guidelines and appendix A of Manual 3A on the transmission equipment rating monitor equipment ratings update process.
The proposed problem statement calls for the incorporation of supporting manual language to ensure the “efficient and reliable operation” and use of equipment DLR systems in various aspects of operations, markets and planning. Callaghan said the opportunities driving the effort include reliability and economic benefits associated with DLR technology.
“The interest here is transparency to members and the reliability mission of PJM,” Callaghan said.
Expected deliverables in the issue charge include stakeholder education of DLRs and potential new or modified governing language in the manuals.
Callaghan said PJM was looking to use the “CBIR Lite” (Consensus Based Issue Resolution) process to come up with a single proposal. The discussions would occur at normal OC meetings and are expected to take more than two months.
Adrien Ford of Old Dominion Electric Cooperative said she disagreed with using the CBIR Lite process and had anticipated more expected deliverables and key work activities in the issue charge. Ford said PJM should be “very careful” to keep the issue narrow if the RTO wants the DLR work done quickly in the OC.
Calpine’s David “Scarp” Scarpignato said he was hoping for a deliverable focused on the placement of DLRs on the grid. Scarp said DLRs are “very important to modernize the transmission grid,” but it will be necessary to make sure their placement is not discriminatory.
Scarp also said he doesn’t know what criteria and guidelines transmission owners plan to use for the installation of DLRs. “I think an important expected deliverable has to be criteria for where to implement DLR.”
Eric Hsia of PJM said the RTO recognizes the importance of DLR placement. Hsia said PJM wanted to focus on adding support language on the physical operations of DLR in the proposed problem statement and issue charge and that the DLR placement issue could better be handled at the Planning Committee in a separate problem statement and issue charge.
Sharon Midgley of Exelon said PJM should be “very careful” in doing a legal review to “respect” the delineation of responsibilities between the TOs and the RTO when it comes to decisions on the placement of DLRs on the transmission system.
“I get a little nervous when I hear things like new requirements and new criteria,” Midgley said.
The OC will be asked to approve the issue charge at the Jan. 13 meeting.
Renewable Dispatch First Read
Darrell Frogg of PJM’s generation department, presented a first read of a problem statement and issue charge to improve dispatching renewable resources and increase forward-looking visibility.
Frogg said PJM is already discussing renaming the issue to “intermittent resource dispatch” instead of “renewable dispatch” to better align with existing language in the RTO’s governing documents. Frogg said PJM wanted to keep the issue broad to include all renewable resources.
The growing number of renewable resources on the grid has led to some “new operational issues and impacted existing issues,” Frogg said, including a greater dependence on the ability to accurately dispatch renewable resources in real time and forecast near-term changes. Frogg said as the number of renewable resources grows, manually managing dispatch becomes more difficult and leads to inconsistent performance when following curtailments and/or basepoints.
Frogg said PJM sees an opportunity to improve several main aspects of renewable dispatch, including developing a method that covers all renewable resources and a streamlined data exchange.
The key work activities of the issue charge include reviewing education on the existing renewable dispatch practices and the expectations from PJM and its members. The goal is to propose solutions to enhance the overall renewable dispatch process.
Areas in scope for discussion in the issue charge are the methods in which PJM dispatches renewable resources, communication of dispatch mode and instructions, and lost opportunity cost eligibility. Out-of-scope items include existing market products and calculations and ongoing revisions such as those related to FERC Order 2222 and the treatment of solar-battery hybrids. (See “Solar-battery Hybrid Resources,” PJM MRC/MC Briefs: Nov. 17, 2021.)
The expected deliverables in the issue charge are changes to resource expectations when dispatched in real time and manual language and potential governing document changes to reflect the proposal.
Work on the issue charge would take place in the OC or its special sessions, reporting out to Market Implementation Committee when needed. The work is estimated to take six months, and PJM was looking to pursue the CBIR Lite approach to develop a proposal.
Scarp said he didn’t think the issue should be part of the CBIR Lite approach. He said PJM staff are “extremely well versed” on the issue and think it can be solved quickly, but the stakeholder process can take longer as members need to be brought up to speed on complicated issues.
“We may end up at the same positions as PJM, but we have to have time to get there in order to vote for it,” Scarp said.
Sean Chang of Shell Energy said he would like to see some education on comparing what other RTOs and ISOs are doing on the renewable dispatch issue.
“Some of the other areas with more renewable penetration have had some challenges operationally, and it could be helpful to compare and contrast,” Chang said.
The OC will be asked to approve the issue charge at its next meeting.
Hoang said the minor changes include updating the Eastern Interconnection Reliability Assessment Group study and PJM participation in the group. Language was added to state that the group will conduct “assessments to identify key reliability issues and the risks and uncertainties affecting adequacy and security of the bulk power system in the Eastern Interconnection.”
The OC will be asked to endorse the changes at its Jan. 13 meeting, with final adoption at the Markets and Reliability Committee meeting Jan. 26.
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.
