A group of six Republican state lawmakers is putting forward a billthat would create a commission to study that question.
The commission would investigate whether it would be feasible for the state to withdraw from ISO-NE and become its own independent grid operator, market administrator and power system planner.
In a hearing of the Science, Technology and Energy Committee on Monday, the primary sponsor Rep. J.D. Bernardy (R) said that costs to consumers are what’s motivating his effort to consider separating from New England’s grid.
“In my campaign, one of the key issues I faced was explaining to constituents why there were skyrocketing costs of electric power,” he said during an informational hearing.
If New Hampshire — a net exporter of power to the rest of the region — were to withdraw from ISO-NE, it could harness the electricity produced in-state to power its own economy and households, he argued.
“Peak power in New Hampshire is a little over 2,000, 2,100 MW. What does Seabrook [Nuclear Power Plant] produce? About 1,200. That’s about 60% of the power for New Hampshire,” Bernardy said.
The proposal was met with significant skepticism by the other members of the committee, who noted that Seabrook’s power is contracted out to buyers in a number of other states and couldn’t necessarily be contained to New Hampshire.
Other committee members also pointed out that there would be immense legal and logistical challenges associated with separating from the regional grid operator.
“By withdrawing from the ISO, we would be blowing a big hole in the regional power system,” Rep. Tony Caplan (D) said.
And, he asked, “how would we be able to provide lower rates for New Hampshire ratepayers given that the administration and regulation and all those services we would have to provide ourselves?”
Maine and Connecticut have both taken on similar assessments — Maine in 2007-8 and Connecticut in 2020 — and neither decided to move forward, said Joshua Elliott, director of the division of policy and programs at the New Hampshire Department of Energy.
Elliott said the agency is neutral on the bill because it would only involve studying the subject. If the legislature does move forward with the proposal, he suggested that it consider recruiting consultants to help put forward a more “substantive” end product.
The other sponsors of the bill are Republicans James Summers, Susan Porcelli, Fred Plett, Jason Janvrin and Yury Polozov.
New Jersey regulators have approved two remote net metering (RNM) projects totaling more than 250 kWdc in the latest of a series of RNM projects given the green light, while the legislature considers a bill that supporters say would make development of such projects easier.
The two Rutgers University projects are among half a dozen projects totaling nearly 1,000 kWdc backed by the New Jersey Board of Public Utilities (BPU) in the last eight months under a 2018 program designed to promote development of solar projects by municipal governments and other public bodies.
The Rutgers projects approved Jan. 11 — an 82.35-kWdc project developed by Rutgers’ Snyder Research Farm and a 173.88-kWdc project developed by the university’s Cook College — followed the board’s Nov. 9 approval of 251 kWdc developed by the Borough of Edgewater, a project located on top of the town’s community center that will feed energy to a second location in the community.
The BPU last year approved a series of solar facilities, including a 141.3-kWdc project to be built at the Sommers Point Sewerage Authority, with power to be shared with the City of Somers Point; a 89.91-kW facility at a property used by the City of North Wildwood; and a 202.5-kW facility at Newton High School.
All the projects were approved under a program, part of the 2018 Clean Energy Act, that allows kilowatt-hours of solar electricity generated by a local government project in one location to be credited to the account or accounts of public entities at other locations that are not geographically connected.
The strategy of removing the requirement that the solar generation occur in the same place that the energy is used enables project development in locations that are not able to operate a solar facility — perhaps because of too much shade, grid connection barriers or other reasons.
The program is similar to the state’s community solar program, which also allows the development of projects in which the electricity is generated and used in different locations. But in that case, the power is sold to a large number of subscribers, at least 51 % of which need to be low- and moderate-income, as opposed to a few public entities under the RNM program. (See NJ Celebrates Completion of First Phase 2 Community Solar Project.)
Under both programs, the customers — which in the RNM program are public bodies — are awarded credits that reduce the cost of their electricity bill.
Promoting Local Government Solar
The BPU’s wave of RNM approvals come as the legislature mulls a bill, A4328, that supporters say would make it easier to develop RNM projects, and opponents — among them the New Jersey Division of Rate Counsel — fear would add to the cost to ratepayer subsidies of the program.
The state is looking to ramp up solar production to meet Gov. Phil Murphy’s goal of reaching zero emissions by 2050, with solar reaching 5.2 GW of capacity by 2025 and 12.2 GW by 2030. The state wants to have 17.2 GW of solar power installed by 2035, a goal more than four times as large as the 4.3 GW of capacity installed by December, BPU figures show. (See NJ Faces Challenges as Solar Sector Hits 4 GW.)
Abraham Silverman, executive policy counsel at the BPU, said the legislature created the state’s remote net metering program to make it easier for municipalities to pursue solar projects. It “fills a void” for public bodies that in several aspects would fit into the community solar program but don’t match the requirement to have a large number of subscribers, he said.
For example, the RNM program helps a public body that may have several locations suitable for mounting a solar project but individually would use either more or less electricity than the project would generate. Under the RNM rules, the demand and electricity generation could be spread across all the locations, allowing the development of a project that would fit their needs.
Silverman said the BPU “has been very, very supportive” of the RNM program. “And you’ve seen a few different places where we’ve provided higher incentive rates for projects owned by municipalities.”
RNM projects enjoy “favorable retail economics,” he said. “They are larger-scale projects, and so benefit from economies of scale, but they sell the power back to grid at retail — rather than wholesale — prices, which makes the project more economically feasible,” he said.
“As we sort of step back and look at the remote net metering program, you’re kind of getting wholesale cost structure, but you’re getting retail revenues,” he said. “And so it’s a significant incentive that’s really only open to municipalities.”
New Opportunities
A4328 would update the rules and regulations of the RNM program to make them similar to those of the state’s Community Solar Energy Program, in which solar developers sign up customers who agree to buy the solar generated energy in return for a discount.
The proposed new RNM rules would define how the credit is calculated and would enable “electric public utilities [to] recover all costs incurred in the implementation of or compliance with the remote net metering program, including the full value of all credits provided to participating customers,” according to the Office of Legislative Services’ analysis of the bill. The costs, however, would be subject to review by the BPU.
The bill also doubles the size of projects allowed in the RNM program, from 5 MW to 10 MW, said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition.
“I think it’s going to open up a whole lot of opportunities for developers and for communities,” DeSanti said. One reason is that A4328 would end the current requirement that a solar array must be on municipal property for the municipality to benefit from the project.
“That was way too restrictive,” he said, adding that bill would allow an array to be located anywhere in the territory of the project’s utility company.
The bill also revises the calculation method by which the BPU determines the maximum size of the project. At present, the size is based on an average of the power used by all the entities or accounts that will receive the power. The revised rules base the maximum size on an aggregation of the entitites’ historical usage, DeSanti said.
“So, this will allow a developer to go in and make a deal with five, six, seven or eight towns, whatever he needs, up to 10 MW, and then basically put it together in a deal,” DeSanti said.
Increasing Ratepayer Burden
Whether the new rules become law depends on the state General Assembly — and Murphy. The Senate version of the bill passed 40-0 on June 29. The Assembly version, having secured the backing of the Assembly Telecommunications and Utilities Committee on Oct. 17, is now before the Assembly Environment and Solid Waste Committee, where approval would lead to an Assembly vote.
Support for the bill is far from universal. In an Oct. 14 letter to the Assembly Telecommunications and Utilities Committee, Brian O. Lipman, director of the Division of Rate Counsel, said the bill would “significantly expand the scope of the [BPU] board’s remote net metering program for public entities,” and expressed concern that it would “result in additional costs to taxpayers.”
“Net metering credits are a form of subsidy that are paid for by other ratepayers,” he said. When net metering customers receive those credits, “rates must be raised for other ratepayers to cover net metering customers’ share of the cost of maintaining and operating the utilities’ electric distribution systems.”
He said the current program rules have two “important” factors that limit the project size, and so the burden on ratepayers: that the proposed facility sits on property with at least one host customer, which will use the energy generated; and the project is limited in size by the total annual usage of the host customers’ electric public utility accounts. The bill eliminates those limits and effectively expands the pool of public bodies that can receive credits, which are subsidized by other taxpayers, Lipman argued.
The rate counsel also expressed concern at the speed and lack of public input in the process set out in the law to enact the rules, and the lack of “public advertisement” and a competitive process.
This would “impair the [BPU’s] ability to assure that the implementing regulations recognize the interests of all stakeholders,” he said.
NYISO on Thursday presented the Installed Capacity and Market Issues Working Groups (ICAP/MIWG) with further revisions to its proposed rules for distributed energy resource aggregations based on stakeholder feedback, but the groups’ members continued to express concern and confusion.
As it is never clear exactly which resources in an aggregation are providing electricity, NYISO has proposed to calculate their reference levels based on lists of average marginal costs for different resource types. “Aggregation-level offers will include a resource type from this list for each hour to indicate the highest-cost resource that is available to produce energy in the aggregation,” according to the ISO. “The NYISO-estimated marginal cost of that resource type will serve as the reference level for the entire aggregation for that hour.”
But there was extensive discussion and questions at the meeting about how exactly NYISO would do this, and how this would influence market bids and signals.
Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, questioned NYISO’s proposed cost-based approach and why it didn’t stick with locational-based marginal prices. He said market participants who possess variable operations, such as crypto miners, may struggle to produce granular reference points to decide whether to make offers and may see “their net revenues being held hostage.”
NYISO responded that LBMPs and bid-based reference levels are based on 90-day historical data, but an aggregation’s composition can change day to day. A cost-based approach would enable aggregators to dynamically reflect different technology types, though the ISO expects that when someone “makes an offer based on their estimated marginal cost of production, they should be able to reflect that.”
2023 Import Rights for Neighboring Control Areas | NYISO
Julia Popova, NRG Energy’s manager of regulatory affairs, said she was concerned that dispatched generators would not be compensated in the real-time market, even though they made bids based on ISO economic forecasting in the day-ahead market showing their units being profitable.
“In real time, there is opportunity to buy out our position, but with everything else going on with DERs, it does not work every time as intended,” Popova said.
“If NYISO can’t give us to the tools to make sure we aren’t dispatched uneconomically, then it is not fair to penalize us” because “we did what we said we would do based on [the] day-ahead,” Breidenbaugh chimed in.
NYISO offered stakeholders offline discussions in response to concerns and told them about upcoming training opportunities to help with onboarding. It expects to begin accepting customer registrations for DER aggregations in mid-April and anticipates the proposed tariff revisions becoming effective in early summer.
The ISO will seek approval of revisions from the Business Issues and Management Committees on Feb. 15 and Feb. 22, respectively, and will return to the ICAP/MIWG to continue discussions on necessary manual revisions.
Zach Smith, NYISO capacity market design manager, said the effort “allows a twofold change”: more accurate representation of installed reserve margins (IRMs) and locational capacity requirements (LCRs) in resource adequacy models, and more accurate capacity accreditation factors for capacity accreditation resource classes.
NYISO scoped out four topics that need to be addressed:
NYISO does not currently capture natural gas constraints, nor start-up notifications for non-baseload units, in the IRM/LCR models. SCRs, although currently modeled, were found to not align with their expected performance and obligations.
But Smith said the ISO expects to spend most of its efforts this year on tackling the problems identified by the MMU by better capturing how ambient conditions impact correlated derates of combined cycle and combustion turbines.
NYISO will spend the first and second quarters analyzing areas for enhancement; the third quarter identifying any solutions; and the rest of the year either prototyping these solutions or making implementation recommendations. It plans to return to the ICAP/MIWG next month to discuss gas constraints, SCR modeling and the correlated derate issues.
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee and Members Committee on Wednesday endorsed a proposal to change the RTO’s accreditation methodology for intermittent resources.
The proposal would revise PJM’s effective load-carrying capability (ELCC) methodology — used to determine the amount of capacity a resource can offer — to limit the hourly output entered in the modeling at the facility’s capacity interconnection rights (CIR) rating.
Currently CIRs are not considered in the ELCC process, but they are used downstream to cap accreditation. The result is that the ELCC value of intermittent resources is overstated and the CIRs that the resources had to purchase to support the ELCC value is understated, Independent Market Monitor Joe Bowring argued. PJM’s current practice of including hourly output above a resource’s CIR rating in its ELCC analysis when setting accreditation has been the source of much of the contention over the two years and is the subject of an ongoing complaint to FERC (EL23-13). (See Stakeholders Challenge PJM in Capacity Accreditation Talks.)
The changes were passed with more than 90% support at the MRC and 89% support at the MC. The PJM Board of Managers is set to consider them this Wednesday; if approved, PJM will file them with FERC the next day.
The provisions also include a transitional mechanism in which existing generators — including those still in development, but already holding interconnection service agreements (ISAs) — can apply for a portion of the available transmission headroom on the grid.
The proposal, submitted by PJM as “Package I,” was approved by the Planning Committee on Jan. 10. Other proposals considered, but ultimately rejected, by the PC would have immediately granted existing resources the CIRs they would be granted under the new system, while others would have required those generators to apply for new capacity ratings and re-enter the queue. (See PJM Planning Committee Endorses Capacity Accreditation for Renewables.)
Generators seeking transitional capacity must file a CIR uprate request during a 30-day window, which is currently set to open on Thursday. The transitional studies determining the amount of headroom that can be granted to resources would begin on March 3, to be completed by April 21.
LS Power Amendment Fails
An amendment to the proposal put forward by LS Power would have required that any resources granted access to transmission headroom through the transitional studies either utilize that allocation or relinquish it.
The company’s Tom Hoatson said the change is a logical outgrowth of stakeholders’ desire in forming the proposal to limit discrimination between resources and would prevent hoarding or the exercise of market power.
PJM CEO Manu Asthana noted the interaction between CIRs and ELCC has long been a divisive issue for stakeholders and said that he believes that rather than introducing an amendment as endorsement is being considered, it would be better to vote on the larger proposal and continue deliberations on headroom utilization separately.
“This is a topic that we’ve worked on for a long time. It’s been very contentious and hard fought to get to consensus,” he said.
Though he could understand the perspective of those who believe that the amendment was an extension of the proposal’s existing non-discrimination provisions, Asthana said he disagreed that the amendment fit into the intent of the package. He also worried that the language would function as a must-offer requirement.
Bowring said that it would be inefficient to have headroom allocated to generators that do not commit to using it and that it would not function as a de facto must-offer requirement — a provision he’s long pushed for. He stated that “the temporary headroom is a valuable product that is being assigned to some resources at zero cost. The failure to require that the recipients of the temporary headroom actually use it means that they are preventing other resources from using the headroom. Without attributing intent, this is a form of withholding that is not consistent with an efficient, competitive market outcome.
“I don’t think it’s an expansion of the must-offer. As much as I would like it to be that, it’s not that,” he said.
PJM staff said that the original text of the amendment would be difficult to implement and inaccurately referenced CIRs rather than transitional headroom. At Asthana’s recommendation, staff worked with Hoatson outside the room while the committee moved onto other agenda items, returning with a reworked amendment.
In objecting to the language’s presentation as an amendment, Manuel Esquivel of Enel North America said it appeared to be an overly constrained provision within a larger proposal, with a lot of moving parts and open questions. Even when a generator’s intent is to absolutely use the additional requested capacity, the dynamic nature of the transitional process may result in a particular generator ultimately not being able to use the headroom they sought.
He worried that the text would effectively function as a requirement that participating intermittent resources must offer into Base Residual Auctions (BRAs). Instead of creating such a requirement through an amendment, he said that should be part of the discussions at the Resource Adequacy Senior Task Force, which is currently engaged in considering changes to the capacity market.
“We’re not comfortable with establishing something akin to a must-offer requirement for all resources in a vacuum,” he said.
Because there was an objection to the text’s adoption as an amendment, it was instead presented as an alternative motion. And because stakeholders ultimately endorsed the main motion, they did not vote on the amendment.
CARMEL, Ind. — System planners last week emphasized that MISO won’t analyze its second portfolio of long-range transmission projects (LRTP) with any preconceived notions.
Matt Tackett, principal adviser of expansion planning, told stakeholders during a Jan. 27 workshop that MISO’s current project map is not a final proposal. He said it’s a “starting point for analysis,” repeating that phrase for emphasis.
Tackett said the concept map was based on “qualitative future considerations” and that a final second portfolio could morph into something entirely different.
“This is a work in progress. It could change before we even begin the analysis,” he said. “Please don’t interpret this as a final proposal or even speculation at what a final proposal could look like.
“We must consider the fact that we’re under a new operating scenario in the future,” Tackett said, adding that the RTO’s resource mix and load profile will be different in future years and generation dispatch will be more volatile.
“It goes without saying that this is a major effort … to further our reliability imperative and effectuate our ongoing fleet change,” Jarred Miland, senior manager of transmission planning coordination, said.
He said any projects staff eventually recommend will have “benefits that far exceed costs.” He promised more information in the coming months on reliability and economic modeling that will inform future decisions.
Clean Grid Alliance’s Natalie McIntire said the first LRTP portfolio’s projects are likely already spoken for, given the amount of renewable generation coming online. She urged that MISO “cast a wide net” for its second effort.
Staff said they haven’t foreclosed the possibility of a 765-kV or an HVDC line in the second portfolio. They also said they are currently drafting benefit definitions for the portfolio’s possible cost allocation. MISO will share the definitions for stakeholder review this spring when the analysis is complete. (See MISO to Test Long-range Tx Allocation Benefits.)
During a Jan. 24 Regional Expansion Criteria and Benefits Working Group meeting, Sustainable FERC Project attorney Lauren Azar said the grid operator is running out of time to finalize and file a cost-allocation approach for the third cycle of LRTP projects, which will focus on MISO South.
Azar said a continuation of the postage stamp rate allocation would be acceptable if MISO and stakeholders fail to propose another, more specific allocation.
“I’m fine if we don’t end up with a new cost allocation, but I know other stakeholders aren’t,” she said. “I would strongly urge them to present proposals.”
Southern Renewable Energy Association’s Andy Kowalczyk asked whether MISO will be able to devise an allocation by June.
Milica Geissler, the RTO’s cost allocation specialist, said the answer was a “Yes, and.” She said an allocation design is contingent on compelling suggestions from stakeholders and ideas proposed in upcoming meetings.
The PJM Markets and Reliability Committee added a discussion of the market seller offer cap (MSOC) and capacity performance quantifiable risk (CPQR) to its Jan. 25 agenda at the behest of stakeholders concerned that the current constructs may not fully reflect the risk of penalties paid during emergency conditions.
Jeff Whitehead, of GT Power Group, said the current MSOC was built on the assumption that emergency performance assessment intervals (PAIs) would be few and far between. However, the 277 PAIs occurring on Dec. 23 and 24 during Winter Storm Elliott has challenged that notion.
With the 2025/26 Base Residual Auction (BRA) approaching and generation owners facing as much as $2 billion in performance penalties stemming from Elliott, Whitehead said it’s important that sellers are able to understand how the storm will impact the offers they can submit. (See PJM Gas Generator Failures Eyed in Elliott Storm Review.)
PJM Vice President of Market Services Stu Bresler said there are two meetings of the Resource Adequacy Senior Task Force (RASTF) — including Jan. 31 — and one Market Implementation Committee meeting before the next MRC meeting. He said the issue can be added to those agendas with the goal of having a proposal to present to the MRC at its February meeting. Given the current timeline for the June BRA, he said actionable market changes would likely require an alternative auction schedule.
Gregory Carmean, of the Organization of PJM States Inc. (OPSI), said that any changes to the auction schedule would be disruptive to states that run their own markets to procure energy.
Noting that the funding for bonus payments is derived from the penalties paid by underperforming generators, Carmean questioned why the capacity performance mechanism results in “exorbitant prices” for ratepayers and doesn’t net out to be cost neutral. Given that energy-only resources aren’t subject to penalties, he also asked why they are eligible to receive bonus payments.
PJM’s Adam Keech said the bonus payments are distributed to any overperforming resources to create an incentive to provide power when it is needed most, regardless of whether it comes from capacity or energy resources.
Jason Barker, of Constellation Energy, said many small or new market participants may not have developed the tools needed to fully model the performance risk to their facilities, creating a roadblock to offering as a capacity resource. A pro forma system where sellers can provide data and receive expectations of how their unit may perform could be a short-term step as broader market designs are considered.
Independent Market Monitor Joseph Bowring said it’s reasonable to raise the narrow issue of the interaction between Elliott and PJM’s market mechanisms.
“It is straightforward to include the PAI data from Elliott in the simulation calculations used to calculate CPQR,” he said. “But is important not to be hyperbolic about the impact of the Elliott PAI. It should come as no surprise to anyone that the market experienced PAI. But this is the first significant PAI event in the history of CP. This can be handled within the existing rules.”
Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), noted that the conversation was occurring little more than a month out from the storm and data collection is still underway. Rather than rushing the MSOC conversation, he pushed for a more cautious approach.
“Overall, we would prefer to have a comprehensive market discussion and go at it that way rather than have a piecemeal and plug a hole, with a couple bandages over it,” he said.
Stakeholders Endorse Expansion of Hybrid Resource Rules
The rollout for the second phase of market rules for hybrid resources was approved by the MRC Wednesday, expanding the definition of hybrid to any combination of fuel types. The first phase created a set of market rules for the most predominant form of mixed-fuel facilities, solar and storage combinations, with the classification and metering language effective Oct. 1, 2022, and the energy market model scheduled to go live this June. The proposal requires FERC approval. (See PJM MRC Moves Forward on Storage, Hybrids.)
The new hybrid definition would allow for more resource pairings, such as hydrogen and solar or gas and solar, to benefit from the market provisions in the first phase, regardless of whether they are paired with storage. The market model for inverter-based storage hybrids is based on the phase one structure.
The proposal approved last week creates a new market model for inverter-based, generation-only hybrids, such as wind and solar modeled on the existing system for wind resources. The EcoMax and uplift parameters currently in place for wind resources are also being applied for hybrids.
Other MRC Business:
Stakeholders endorsed revisions to the charter for the emerging technologies forum to shift toward an emphasis on stakeholder discussion and debate, rather than a focus on education. The changes also include references to new Manual 34 language regarding forums, including added clarification that discussions in forums cannot be used to bypass the existing stakeholder issue resolution process.
The MRC approved a proposal to change how PJM models power flows in its day-ahead model to look at all 24 hours for the reference date. With changes in load patterns, particularly from behind-the-meter solar and data center development, PJM’s Amanda Martin said additional accuracy in aligning day-ahead and real-time flows is necessary. (See “First Read on Changes to Day-ahead Zonal Load Bus Distribution Factors,” PJM MIC Briefs: Nov. 2, 2022.)
Members Committee
Stakeholders Endorse Pathway for Issues to be Brought Directly to MC
The Members Committee endorsed a motion from Adrien Ford, of Old Dominion Electric Cooperative, to allow members to bring some issues best addressed by the MC directly before the body through a problem statement and issue charge, rather than having to be first considered by lower committees.
The manual revisions were endorsed by the committee by acclamation with eight objections and five abstentions, all in the end-use customer sector.
Poulos said it’s best to have a problem statement and issue charge whenever possible to allow stakeholders to have a clear understanding of why a topic is being discussed. However, he worried that requiring those could lead to administrative discussion down the road that gets in the way of substantive work.
He asked Ford if she would be amicable to an amendment to her language to change the requirement that a problem statement and issue charge be approved by the MC be changed to recommend, but not mandate, that process. Such a change would also allow for issues to be voted on by the committee the same day they’re broached.
Ford said she could not accept the amendment, as the language was drafted by a group of stakeholders over a long period of time.
PJM Considering New Non-performance Charge Billing Schedule
PJM CFO Lisa Drauschak presented a series of adjustments the RTO is considering to its non-performance charge billing schedule to extend the amount of time market participants have to make payments when performance assessment intervals (PAIs) fall near the end of the delivery year.
Currently, billing is split between the remaining months in the delivery year after the charges have been determined for a generator. For PAIs in the summer this leaves as much as nine months for payments to be made, but for Winter Storm Elliot there will only be three months to make payments once the penalties have been determined.
PJM’s proposal would amend the tariff to allow payments to be split over an additional six months if less than six months remain in the delivery year once charges have been determined.
A second option being considered is to allow members who have been assessed penalties to elect to either pay them across the greater of the remainder of the delivery year, or three months, with no interest, or to have a six-month floor with interest added at the FERC prevailing rate. The alternative is based on stakeholder feedback received during the Jan. 24 meeting of the Risk Management Committee regarding the possibility of incorporating interest into the payment methods.
PJM General Counsel Chris O’Hara said that under the current language, if there were to be a PAI in the last two months of a delivery year, the collection period would already extend into the next delivery year, so the proposal is also an attempt to fix a broken provision.
SERC Reliability has levied penalties totaling $320,000 against Dominion Energy (NYSE:D) subsidiary Virginia Electric and Power Co. for violations of NERC reliability standards, according to a pair of settlements between the utility and the regional entity approved last week by FERC (NP23-9).
NERC filed the settlements Dec. 29 in its monthly Spreadsheet Notice of Penalty. On Friday the commission said that it would not further review the filing, leaving the penalties intact.
SERC assessed separate penalties against the utility’s generation and transmission divisions (respectively dubbed VEP-PG and VEP-Trans in the filing). Both involved infringements of FAC-008-3 (Facility ratings) and its predecessor, FAC-009-1 (Establish and communicate facility ratings), and were self-reported.
According to requirement R1 of FAC-009-1, generator owners (GO) and transmission owners (TO) must “each establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associated facility ratings methodology” (FRM). Requirement R6 of the successor standard — which became effective in 2013 and has since been superseded by FAC-008-5 — contains nearly identical language.
Virginia Electric initially reported to SERC that, as both a TO and GO, it was in violation of FAC-008-3. The RE later determined that the infringement began under the earlier standard.
During an extent-of-condition assessment on April 2, 2020, caused by a suspected FAC-008-3 violation at a solar facility, VEP-PG found that the low-side and high-side cables in the facility’s generation step-up transformer had not been included in its facility ratings calculation, as required by the FRM. The utility subsequently performed a walk-down of all 102 facilities to which FAC-008-R6 applied, discovering 41 incorrect ratings that resulted in 28 uprates of up to 200%, and 13 derates of up to 33.14%.
VEP-Trans discovered its violation on Nov. 13, 2019, during an internal data validation process. According to its self-report, the utility found that the facility rating for a 500-kV networked line was inconsistent with the FRM because the rating had been changed during an upgrade without confirming the change was made in the field.
After SERC requested that VEP-Trans walk-down four transmission stations to check their ratings, the utility found 40 incorrect ratings. It then began a full system walk-down of all its bulk electric system transmission facilities on June 1, 2021. The full walk-down is expected to be completed by June 2025, but according to SERC’s filing, VEP-Trans had reviewed 244 facilities by Sept. 29, 2022, discovering misratings at six of them.
SERC concluded that the violations by both VEP-PG and VEP-Trans posed a moderate risk to the reliability of the bulk power system on the grounds that “incorrect ratings could cause system instability because planning models and system operating limits would not accurately reflect the true limits of the facility.” In the case of VEP-PG, the RE did note that the length of time of the violation and the number of affected facilities were aggravating factors.
Mitigating actions by VEP-PG include revising its FAC-008 compliance procedure document, along with other internal documents, implementing an “over-arching power generation document … to ensure consistency fleet-wide,” and conducting training on change management documents and requirements. VEP-Trans’ mitigation steps include conducting a third-party review of its facility rating process and streamlining its notification process, along with the full walk-down of its facilities.
SERC noted several credits to both VEP-PG and VEP-Trans for self-reporting the violations and demonstrating a high level of cooperation. However, it still assessed penalties of $130,000 against VEP-PG and $190,000 against VEP-Trans.
The Nuclear Regulatory Commission told Pacific Gas and Electric last week it would have to file a new application to keep California’s last nuclear generator, the Diablo Canyon Power Plant, operating beyond its planned closure dates in 2024 and 2025.
To expedite the renewal process, PG&E had asked the NRC to review a license application it filed 13 years ago. The NRC said it could not review the old application but would consider a waiver that might allow Diablo Canyon to continue operating as the commission weighs a new application.
PG&E said it had anticipated the decision and planned ahead.
“PG&E’s project plan considered this regulatory path, and we have been developing application materials and supporting documents to support a filing with the NRC later this year,” the utility said in an emailed statement.
PG&E filed its previous renewal application in 2009 but withdrew it in 2018, based partly on the determination by state officials that the plant would not be needed to meet future demand for electricity.
Circumstances changed, however, as the state faced energy emergencies during the past three summers including rolling blackouts in 2020 and near misses in 2021 and 2022.
Amid the crisis, Gov. Gavin Newsom and state lawmakers took steps to retain Diablo Canyon’s 2.2 GW of baseline power until at least 2030, and the U.S. Department of Energy awarded PG&E $1.1 billion to keep the plant open. (See DOE Grants PG&E $1B for Diablo Canyon Extension.)
In October, PG&E asked the NRC to review its prior application and offered to supply updated information as needed.
The NRC denied the request in a Jan. 24 letter to PG&E.
“The NRC staff has determined that resuming this review would not be consistent with our regulations or the [NRC’s] principles of good regulation and that there is no compelling precedent to support your request to resume the review of your withdrawn application,” the letter said.
“This decision does not prohibit you from resubmitting your license renewal application under oath and affirmation, referencing information previously submitted, and providing any updated or new information to support the staff’s review,” it said.
PG&E had also asked for a waiver under a federal regulation that allows a nuclear plant to keep operating past its license expiration date if it files a renewal application at least five years before the existing license expires. In that case, the “existing license will not be deemed to have expired until the application has been finally determined,” the regulation, 10 CFR 2.109(b), says.
PG&E asked the NRC for a waiver of the rule’s time requirement if it submitted a new application by Dec. 31, 2023. The current operating licenses for Diablo Canyon’s units 1 and 2 expire in November 2024 and August 2025, respectively.
PG&E’s waiver request remains under NRC review.
“The NRC staff has not made a determination on your request for an exemption from 10 CFR 2.109(b), which is included in your October 31, 2022, letter,” it said. “The NRC staff is evaluating that exemption request and expects to provide a response in March 2023.”
PG&E said in a statement that NRC’s decision had “clarified the regulatory path PG&E will follow regarding the license renewal application (LRA) process, while allowing the company to leverage work already reviewed in our 2009 LRA. PG&E intends to submit a new application by the end of 2023.”
Of the $194 trillion in investments that BloombergNEF projects will be needed for the world to even get close to limiting climate change to 1.5 degrees Celsius by 2050, 47% will be targeted at electric vehicle sales, according to BNEF CEO Jon Moore.
Transportation electrification is the key theme at the two-day BNEF Summit in San Francisco, and Moore opened the event on Monday with a rundown of the numbers its analysis shows will be driving the transition, whether it is based purely on economics or on the 2050 net-zero targets set by the 2015 Paris Agreement.
BNEF CEO Jon Moore | BNEF
“Assuming we chose the most economic solutions … that gets us to 2.6 degrees, so not in line with Paris,” Moore said. Based only on targets, “we can actually bend the curve to about 1.77; so not to 1.5, but 1.77.”
Similarly, according to BNEF’s 2022 New Energy Outlook, greenhouse gas emissions from transportation could peak in 2024 in a net-zero scenario, versus 2028 in the economic scenario.
Moore’s numbers showed other significant gaps between BNEF’s economic transition scenario (ETS) and its net-zero scenario (NZS). For example, a transition based on economics would generate $119 trillion in investments — about 33% less than $194 trillion for net zero — with again almost half going to EV sales.
Either way, he said, “the scale of investment required, literally in the next 30 years, will be huge.” Moore sees encouraging signs in the $466 billion in investment that transportation electrification snagged in 2022, which was “up 54% year on year, which is … pretty amazing.”
Passenger vehicles drew the lion’s share of those dollars, and will continue as a major factor, he said, adding that more than 10 million EVs were sold globally last year. They will also account for more than half of EV battery demand, which could total as much as 6.6 TWh by 2035 in the NZS, Moore said. BNEF see similar, dramatic growth in lithium demand, reaching 5.9 million metric tons by 2035 — an 18-fold increase over 2020.
EV sales will account for almost half of all climate investments over the next decades, whether in an economic or net-zero transition. | BNEF
“So, lithium will become absolutely key as an enabler and as a potential bottleneck in the transition,” he said.
The Inflation Reduction Act could at least jump-start the supply chain buildout needed to meet that demand. BNEF has tracked more than $27 billion in supply chain investments since the law was passed, with about 60% of that total going toward EV battery plants.
One interesting point, Moore said, is that in the NZS, EV battery demand peaks in 2035, not 2050, “because if you want to, by 2050, decarbonize your fleet, you really have to be selling a decade or so earlier.”
Aviation is Hydrogen’s Sweet Spot
Moore framed BNEF’s figures as the company’s attempt to cut the “noise” in energy analysis — that is, the biases and errors in judgment that can skew figures.
Minimizing that noise — with extensive research and algorithms — is “really important because we’re going to spend tens, hundreds of trillions on the energy transition,” Moore said. “Every error in judgment that we make, every deviation from how the world progresses, is either an underinvestment or an overinvestment, so it’s actually very expensive.”
Disagreement is inevitable, he said, but “the idea is to bring down the cone of disagreement.”
“Economics alone won’t get us to net zero,” Moore said. “We’re going to need to bend the curve somehow, and policy is going to be one of the ways that we will do that.”
Policy could be critical in increasing the amount of clean power on the grid, as BNEF is anticipating that carbon-free electricity will account for just over one-half of the GHG emissions reductions needed to keep climate change to 1.77 C.
Wind and solar account for 65% of global power supply by 2050 in the ETS, versus 76% in the NZS, Moore said. Green hydrogen, bioenergy and carbon capture will play smaller but significant roles, together providing about 20% of emissions reductions by 2050, he said.
The IRA has triggered a wave of new investment in a North American EV supply chain. | BNEF
The IRA could have a significant impact here as well, by stimulating “a lot of different technologies,” Moore said. BNEF sees the law’s clean energy incentives expanding solar from about 40,000 GW to 50,000 GW by 2030, and wind from 25,000 GW to 35,000 GW.
The use of green hydrogen will also grow, Moore said, but BNEF sees aviation as its main market, followed by shipping and then transportation.
Hydrogen use in aviation will be for “short and medium haul,” he said. “For long haul, there will be biofuels and synthetic kerosene.
“For shipping, it will be ammonia and methanol from hydrogen, and on the road, it’s about 10% of [heavy-duty vehicles] and 15% of buses,” he said.
But BNEF sees hydrogen and electricity as complementary — with each serving different sectors — as opposed to competing. Aviation, shipping and steel will be “hydrogen-centric,” Moore said, while buildings, roads and other industries will be “electricity-centric.”
Staff Working to Understand Forced Outages in December Storm
ERCOT told its stakeholders last week that it is gathering information from its generators about the high number of outages during the December winter storm.
Staff told the Technical Advisory Committee during its Jan. 24 meeting that they have sent requests for information and its weatherization teams to generator resources that suffered forced outages during the Dec. 22-24 event. Thermal outages peaked around 13 GW, and gas supplies were again curtailed as an unwelcome reminder of the deadly February 2021 winter storm that killed hundreds of Texans and caused billions in economic damages. (See “ERCOT: December Storm ‘Non-event’,” PUC Closes in on ERCOT’s Market Redesign.)
Dan Woodfin, vice president of system operations, promised a more comprehensive report, saying staff are combining the information from the RFIs and will analyze the more detailed information.
Saying that ERCOT’s outage scheduler tends to understate outages, Independent Market Monitor Carrie Bivens asked Woodfin whether staff intended to do a true-up with telemetered values.
“Our intention is to look at telemetry and values, the outage scheduler and the results of the RFI, and kind of put it all together,” he said.
ERCOT’s preliminary analysis found gas restrictions in North Texas and operational flow orders issued to prevent gas flowing beyond contract maximums resulted in some curtailments and generation capacity. It also found that reduced renewable generation was not a large factor during the event.
Load peaked at 73.96 GW on Dec. 23, a 16-GW increase from ERCOT’s previous December record. The grid operator’s models projected a nearly 71-GW peak as the storm approached. Woodfin said other grid operators had similar problems predicting load, but that ERCOT’s miss had little effect on market reliability.
NRG Energy’s Bill Barnes took exception to the remark.
“You’re always going to get some type of market response based on ERCOT’s forecast. We look at it as a really big input into our decision-making,” he told Woodfin. “When there’s an under-forecast, that will probably result in a lower offer into the day-ahead [market], which is an economic commitment, which would mean you would have to take other additional [out-of-market] actions. The response that you get from the market? A lot of that comes from … what you guys think.”
Staff plan to engage with TAC’s Wholesale Market Subcommittee on the forecast error.
ERCOT deployed nearly 2.7 GW of its new firm fuel supply service (FFSS) Dec. 22-25 during the event. However, it failed to notify all market participants of the deployment or recall, as required under its protocols, and staff made system changes in January to correct the error.
Staff are drafting new protocols to improve existing language as they prepare for the next FFSS obligation period later this year. The changes are expected to improve the process for approving or instructing the restocking of fuel; offer disclosure reporting; incorporate an alternative FFSS resource concept; and improve qualified scheduling entities’ (QSEs) process for FFSS testing.
RUCs Continue to Increase
ERCOT staff’s annual report on reliability unit commitments led some stakeholders to call for market-based solutions after a second consecutive year of heavy RUC usage.
The grid operator said 8,244.8 instructed RUC resource-hours in 2022 resulted in 7,910.5 effective hours. That was up from the 3,853.1 effective resource-hours in 2021 and a significant increase from the two years prior, when a total of 421.8 effective resource-hours were deployed.
The increased usage is a result of ERCOT’s reliance since the 2021 winter storm on a conservative operations posture that maintains more reserves sooner. Bivens told lawmakers last year that the practice could add more than $1 billion to customers’ bills in 2022.
“We have a giant increase in RUCing some really old generators,” David Kee, CPS Energy’s director of energy market policy, told staff. “It’s causing some concerns in my shop, and we’re thinking about what we’re doing to these generators. … We’re basically running them into the ground. The more you lean on these generators and bring them online for reliability reasons, you’re going to find they’re going to break.”
ERCOT’s Dave Maggio said the average age of RUCed units was between 40 and 60 years. More than 87% of the effective resource-hours addressed capacity concerns, with 12.9% needed for local thermal congestion or voltage concerns; all of 2020’s RUCs were used to meet local congestion or voltage issues after a hurricane damaged transmission facilities in the Rio Grande Valley.
Pressed on staff’s “desire” to reduce RUCs, Kenan Ögelman, vice president of commercial operations, agreed there is a “potential better approach to procuring coverage for the uncertainty that we are dealing with.”
Ögelman said the grid operator expects to continue conservative operations but will be “looking at” modifications or improvements to RUCs. A long-term, market-based solution focused on revenue adequacy resides at the Public Utility Commission, he said, but priorities have yet to be established.
ERCOT paid out $34.11 million in RUC make-whole payments last year that was almost exclusively covered by capacity-short charges. It also clawed back $24.85 million. Those numbers were $404,000 and $484,000 in 2020, respectively.
Staff also said the delayed real-time co-optimization (RTC) project will be brought before the Board of Directors in June after they perform due diligence on the market mechanism favored by the Independent Market Monitor and many market participants.
ERCOT’s Matt Mereness said the project, put on hold almost two years ago after the 2021 winter storm, still has a $51.6 million budget line item and a three-and-a-half-year timeline “because we haven’t revisited it.”
The RTC tool would expand ERCOT’s real-time market by clearing energy and ancillary services every five minutes, as most other grid operators already do. The PUC in 2018 directed ERCOT to add RTC in 2018; it opened a rulemaking in December 2020 for its implementation (51588).
The project’s impact analysis will have to be revisited because of inflation’s toll. Staff will also reassess its scope with an eye of resuming RTC work in July.
“From a reliability perspective, it’s the next thing that we really do need,” Mereness said. “We’re not blind to the risk of this project of getting going, but we also know that we need to move forward on it. The reality is there are things going on at the commission. As that work [for ERCOT] comes out, it will have to be prioritized with other work.”
Subcommittee to Charter Credit Group
TAC delegated the soon-to-be-disbanded Market Credit Working Group (MCWG) to develop a proposed charter, structure and name for a new working group that will report directly to the committee. The group will then replace the MCWG, which had provided input on credit-risk management issues to TAC’s Wholesale Markets Subcommittee.
The stakeholder group will give market participants a voice in market credit issues after the board’s Reliability & Markets Committee determined that staff should report to it on credit issues, and it moved in December to disband the Credit Working Group (CWG). The group was shifted last year to the R&M’s purview from the Finance & Audit Committee, where it had been since 2004. (See “ERCOT Gets 1st Adjunct Member,” ERCOT Board of Directors Briefs: Dec. 19-20, 2022.)
Speaking for Reliant Energy Retail Services, Barnes, a regular CWG attendee, pushed for the new group to include credit professionals, saying his company’s credit pro recommended a voting structure. Other members stressed the importance of market diversity within the group.
The new group’s responsibilities will likely include a credit review of all future nodal protocol revision requests, as required by NPRR1157 and formerly carried out by the CWG.
TAC Elects 2023 Leadership
Jupiter Power’s Caitlin Smith and South Texas Electric Cooperative’s Clif Lange take their leadership seats for TAC. | ERCOT
Committee members re-elected by acclamation South Texas Electric Cooperative’s Clif Lange as their chair for 2023. Having recently been promoted as the cooperative’s general manager, Lange has asked that TAC meetings be moved to Tuesdays this year.
Members also elected Jupiter Power’s Caitlin Smith as vice chair. American Electric Power’s Richard Ross also ran for the position.
The committee’s 2023 subcommittee leadership was approved as part of the combination ballot:
Protocol Revision Subcommittee (PRS): Martha Henson (Oncor) as chair and Diana Coleman (CPS Energy) as vice chair.
Retail Market Subcommittee: Deborah McKeever (Oncor) as chair and John Schatz (Luminant) as vice chair.
Reliability and Operations Subcommittee: Chase Smith (Southern Power) as chair and Katie Rich (Golden Spread Electric Cooperative) as vice chair.
Wholesale Market Subcommittee: Eric Blakey (Pedernales Electric Cooperative) as chair and Jim Lee (CenterPoint Energy) as vice chair.
Most of the leadership are holdovers, with McKeever and Schatz switching positions. Coleman, Blakey and Lee are all new to their roles.
Members Endorse Five NPRRs
TAC unanimously approved NPRR1144, which provides a limited exception to the requirement that loads included in an ERCOT-polled settlement (EPS) metering facility’s netting arrangement only be connected to the grid through the facility’s metering point(s). The exception would allow no more than 500 kW of auxiliary load connected to a station service transformer be connected to a transmission or distribution service provider’s (TSP/DSP) facilities through a separately metered point using an open transition load transfer switch listed for emergency use.
The measure passed 29-0, with CenterPoint abstaining.
TAC unanimously endorsed four other NPRRs on a combination ballot with a change to the Planning Guide (PGRR) that, if approved by the board, would:
NPRR1147: set fast frequency response’s ancillary service offer floor 1 cent/MW lower than other responsive reserve services categories to allow FFR’s procurement up to the current limit, without proration with other categories.
NPRR1149: charge QSEs an ancillary service failed quantity if their supply responsibility is not met in real time by their portfolio’s resources, based on a comparison of their real-time telemetry.
NPRR1151: eliminate the protocol requirement that the PRS hold at least one meeting per month.
NPRR1153: add two existing fees (public information request labor and ERCOT training) to the grid operator’s fee schedule; create a $500 registration fee for resource entities, TSPs and DSPs, and subordinate QSEs; delete the system administration fee’s current value and the map sales fee; and restructure existing fees for generator interconnection or modification, full interconnection study applications and wide area networks.
PGRR102: require resource entities and interconnecting entities to provide operations dynamic model quality test results that demonstrate appropriate performance for submitted operations dynamic models, and make non-substantive clarifying changes.
