The Organization of MISO States (OMS) has released a position statement in support of a downward-sloping demand curve in MISO’s capacity auction.
MISO’s state regulators drafted language that said the existing vertical demand curve may not sufficiently value the reliability contribution of excess capacity and might cause load-serving entities to over-rely on the RTO’s market to procure capacity. They also said the vertical design might be hastening resource retirements and is likely not sending price signals that would spur investment in new generation.
The regulators said the grid operator’s current resource adequacy “has led to capacity shortfalls in part of the MISO footprint, may fail to maintain appropriate price signals and may not lead to reliability going forward.”
The Kentucky Public Service Commission and the Public Service Commission of Wisconsin abstained from voting on the statement, and the Manitoba Public Utilities Board did not participate in drafting the letter. However, the Kentucky commission added that it “strongly believes that MISO must immediately endeavor to address the most prominent issues with its capacity market, through actions which include, but are not limited to, implementing a downward-sloping demand curve.”
OMS said it “looks forward to contributing to the final design of a revised demand curve” and said its “support of a revised demand curve is contingent on reviewing and approving MISO’s final proposal.”
OMS also warned that it will oppose a minimum offer price rule in the capacity auction.
During the OMS’ annual meeting in October, North Dakota Commissioner Julie Fedorchak said the organization’s members still need to know the final shape of the proposed curve and understand the options for states to self-supply or opt out in meeting their reliability needs.
Fedorchak also said the sloped demand curve’s formation should be done in conjunction with other resource adequacy measures, like improved scarcity pricing and a new generation valuation that can provide necessary system attributes. She said a sloped demand curve is “just one tool” in the quest for resource adequacy.
CAISO’s proposed extended day-ahead market (EDAM) for its Western Energy Imbalance Market could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection, a new study commissioned by CAISO found.
The report by Energy Strategies was similar to a study the consulting firm performed last year that found a single RTO covering the entire U.S. portion of the interconnection could save the region $2 billion a year in electricity costs in test-year 2030. The study was prepared for state energy offices in Colorado, Idaho, Montana and Utah with funding from the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
The firm’s EDAM study for CAISO built on that work. It examined operational savings obtained through more efficient dispatch and management of transmission capacity, lower operating reserve requirements, and the removal of transmission wheeling costs in the market footprint. It also looked at capacity reductions from regionally shared planning reserve requirements met through geographic diversity of generation resources and peak demand.
“The methodology and the underlying databases used to perform this assessment were consistent with those that my firm used to perform the state-led market study for a consortium of Western states,” Energy Strategies Principal Keegan Moyer said Friday in a meeting hosted by the Committee on Regional Electric Power Cooperation (CREPC). CREPC is seeking to play a larger role in Western market formation. (See CREPC Seeks to Become an OPSI for the West.)
The EDAM study differs from the state-led study because it dealt with a specific market proposal instead of a generic RTO framework, Moyer said.
“The framework that we assume here is really just based off of a sharing of resources, assuming planning reserve margins stay consistent, and we just begin to plan for a consolidated peak relative to individual peaks,” he said. “It’s really quite simple. It’s just a regional arbitrage of non-coincident peaks.
“There are, of course, other energy benefits that were not captured in this analysis,” he said. “So, for example, an EDAM could produce price signals that improve the efficiencies of transmission planning. That would be helpful to see a day-ahead price process to plan the transmission grid better, but that benefit isn’t captured here.
“Markets also tend to increase access to public-policy renewable resources,” Moyer said. “The reason for that is that you don’t have to wheel them across the system and/or you have different settlement points or different transaction options that are typically seen in SPP and MISO and help to increase that offtake optionality for those resources. So, it just provides better access to those low-cost wind regimes and solar regimes.”
The Western Energy Imbalance Market (WEIM) operates in real-time to share lower-cost and renewable resources among its participants, which now number 19. It has generated nearly $3 billion in benefits since it launched operations eight years ago. (See WEIM Benefits Top $500M, Near $3B Total.)
The fast-growing WEIM produced $739 million in savings for its 15 participants last year and $325 million in 2020 for its then-11 members. Energy Strategies said the EDAM would more than double the average of $525 in annual benefits from the past two years.
California would be the single largest beneficiary, with about $309 million in benefits in 2030, it said. All other Western states combined would save $886 million in 2030, including operational and capacity savings.
“An EDAM footprint across WECC causes California operational costs to decline by 6.2% from the status quo,” the firms said.
The operational-only benefits of the EDAM would equal 78% of the operational savings from a single all-encompassing Western RTO, as modeled in the state-led study, it said. Including capacity savings, the EDAM would achieve 60% of the benefits of a Western RTO.
The report bolstered CAISO’s sales pitch to Western entities to join the EDAM once it is approved.
CAISO fast-tracked the EDAM stakeholder initiative this year amid competition for Western market share by SPP, which is pursuing its own day-ahead Markets+ program and a Western RTO.
In a Nov. 14 meeting, CAISO presented its draft final proposal for EDAM with hopes of finalizing it next month and seeking approval from its Board of Governors and the WEIM Governing Body in February. (See CAISO Finalizing Plan for WEIM EDAM.)
“Some of the design is still in flux, but we’re kind of at the tail end of the design phase,” CAISO COO Mark Rothleder said at the start of Friday’s CREPC meeting. “Hopefully these additional data points, in terms of the value proposition of EDAM, help in the final stages of the process and really understanding its total value proposition.”
Texas lawmakers and ERCOT stakeholders did not hold back last week as they took their first shots at the Public Utility Commission’s proposed redesign of the grid operator’s market.
“The end loser is the end user,” Sen. Donna Campbell (R) said during a Thursday hearing of the Senate Business and Commerce Committee. “This plan is so convoluted, [and] a long timeline to be put into place, that it’s a setup for failure for everybody.”
Campbell was one of several senators who cast doubt on the PUC’s proposals, chief among them the performance credit mechanism (PCM). The design would require load-serving entities to buy performance-based credits from generation resources that meet reliability standards. It has been widely portrayed as throwing extra money at dispatchable generators and ignoring cheaper renewable resources.
The PCM is one of six market designs the commission has asked ERCOT stakeholders and the general public to provide feedback on by Dec. 15. The commission only rolled out the designs earlier in November after months of analysis and modeling by two consulting firms. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
The performance credits must be produced during the highest reliability risk hours to meet the reliability standard. LSEs can purchase the credits, awarded to resources through a retrospective settlement process based on availability during the riskiest hours, according to their load-ratio shares during those same periods. This allows generators and LSEs to trade credits in a voluntary forward market, the consultants said. Generators must participate in the forward market to qualify for the settlement process.
San Francisco-based Energy and Environmental Economics (E3), which was paid $614,000 for its work, recommended a forward reliability market that has been called a “straight-up forward capacity market.” Other designs it analyzed included an LSE reliability obligation and a backstop reliability service that the PUC first proposed last December.
Texas Sen. Charles Schwertner | Business & Commerce Committee
“To be quite frank, I don’t see … a requirement for new generation,” B&C Committee Chair Charles Schwertner (R) said. “That’s what I think we need to be focusing on: … ensuring we get what we need as a state. The bottom line is we need more dispatchable thermal generation because of the changing characteristics of the world and the federal pieces of law that allow for non-dispatchable to be really incented. Texas has to respond.”
The state’s politicians have focused on new dispatchable thermal resources since the February 2021 storm, despite the fact that they, like all resources, failed to perform during the event. PUC Chairman Peter Lake said E3’s analysis recommended that the PCM’s reliability payments only go to “truly reliable sources” that can commit in advance. He said that by reserving revenues for those resources, the PCM’s expected costs are $200 million cheaper than ERCOT would be expected to pay in 2026 “in the absence of any reform.”
Schwertner asked Lake how fast Texas would see the 5.6 GW of gas-fired capacity that E3 said would be on the system by 2026.
“As always, it depends on a number of variables, [the] first of which the generators would tell you is regulatory certainty,” Lake said, noting E3 expected it would take three or four years to build out the ERCOT system. “Some generators have expressed to us that once they have regulatory certainty, they’ll start building generators concurrently.”
“Are they prepared to come before us today and promise they’ll do that?” Schwertner asked.
“I’ll leave that to them,” Lake responded.
“Yeah, they’re not going to be here today,” Schwertner said.
The lawmakers zeroed in on the costs of the proposed designs and whether they will incent the dispatchable generation. E3 said the recommended designs would improve ERCOT’s loss-of-load expectation (LOLE) to 0.1 day/year by 2026 at an incremental cost of $460 million over the current energy-only construct’s total customer costs of $22.3 billion. A hybrid design combining the backstop reliability service and dispatchable energy credits would be most expensive at an incremental increase of $920 million a year.
Carrie Bivens, ERCOT’s Independent Market Monitor, said the E3 report doesn’t accurately model the operating reserve demand curve, the market mechanism that values the market’s operating reserves based on their scarcity and reflects that value in energy prices.
“This will understate the future revenues of the energy-only market and therefore alter the build and retention signals for resources,” Bivens said. She said E3 also overstates generator retirements by 2026 at 11 GW, resulting in an LOLE that is higher than it should be.
“We don’t see 11,000 MW of retirement. … That affects many of the conclusions throughout the report,” Bivens said.
She allowed that the PCM could be designed to send appropriate price signals “consistent with competitive market principles,” but the backstop reliability service would be costly because it would immediately sideline about 5 GW from the energy-only market and withhold it at the price cap, she said.
“That’s economic withholding and that will serve to increase energy revenues in the short run,” Bivens said.
The IMM has recommended that ERCOT develop a two- to four-hour day-ahead capacity product to account for the increased uncertainty associated with intermittent generation, load and other factors. It says the product could be deployed to bring online longer lead-time units when the grid operator detects operating conditions are “departing from expected conditions.”
Speaking for Texas Industrial Energy Consumers’ commercial customers, Katie Coleman said she shared Bivens’ concerns. She said the E3 report’s newest recommendations are “new spins on old concepts … essentially, the Northeastern-style forward capacity market.”
The PCM “is still fundamentally creating an electricity tax where customers are being mandated to pay a certain amount to generators. All the complexity in this report is just figuring out what’s the size of that tax,” Coleman said. “None of these proposals guarantee any new investment. None. The PUC does not have the authority to command capital. You can create incentives based on reports from a consultant, and you can hope that the capital markets respond, but there is no guarantee that they will. … If they don’t, what happens is customers pay a penalty price.”
“It seems like the loser is always the end user, and this is getting really, really expensive,” Sen. Lois Kolkhorst (R) said. “We can come out with all these proposals, but nobody’s willing to really say, ‘I’m going to do that.’ So, there’s market uncertainty.”
Lake responded to the repeated comments and questions about increasing costs to ratepayers with the same message, saying, “We can deliver 10 times improvement in reliability for roughly the same or even lower cost to our consumers in the absence of action.”
Once it receives stakeholder input next month, the PUC plans to issue its final market design, which will then be vetted by lawmakers early next year.
“I’m looking forward to see what the marketplace and the public tell us,” Lake said.
The California Public Utilities Commission last week increased the state’s multibillion-dollar commitment to transportation electrification by approving a $1 billion, five-year effort to provide charging infrastructure for electric vehicles.
Approximately 70% of the funds will be dedicated to charging medium- and heavy-duty vehicles; the rest will be for light-duty EV charging at or near multifamily housing complexes, with priority given to investments in low-income, underserved and tribal communities.
“This decision marks what I think is an important milestone in our role in promoting transportation electrification and achieving the state’s very ambitious climate goals,” said Commissioner Clifford Rechtschaffen, who led the effort. “Transportation emissions, as we often hear, are the state’s largest share of greenhouse gas emissions. They’re also responsible for the largest share of harmful air pollutants such as NOx, which causes ozone, and particulate matter, which has very harmful health effects.”
The 220-page decision adopting a Transportation Policy and Investment Plan also is meant to consolidate and streamline the CPUC’s efforts to fund transportation electrification by revamping the piecemeal approach it has taken in a dozen decisions since its first EV-funding rulemaking in 2009, Rechtschaffen said.
“The decision today results from over three years of hard work by staff and very engaged stakeholders,” he said. “Until now our electrification funding decisions came as a result of individual and really ad hoc applications for programs by each of the utilities. These programs weren’t especially well coordinated” and were often slow to win approval, requiring evidentiary hearings and long decision-making processes.
The CPUC has approved $1.8 billion over the years for “a whole host of utility programs, [including] light-duty and medium-duty market segments, workplaces, forklifts, school buses and many more. But as we gained more and more experience in this space, we thought it better to replace this ad hoc approach with something that’s more uniform, more streamlined and hopefully faster, and that’s what’s been developed here.”
Developments in state EV policy made funding programs more urgent, he said.
Gov. Gavin Newsom issued an executive order in September 2020 requiring that all new light-duty vehicle sales be zero-emission vehicles by 2035 and all new medium- and heavy-duty vehicle sales to be zero-emission by 2045. The California Air Resources Board adopted similar regulations in August as part of its Advanced Clean Cars program.
In October 2021, the CPUC, California Energy Commission (CEC) and the governor’s Office of Business and Economic Development met jointly to weigh the need for an additional 1.1 million light-duty public and shared EV chargers to meet the state’s transportation decarbonization goals, requiring a rapid acceleration in the spread of EV charging infrastructure by 2030.
An estimated 157,000 chargers will be needed for medium- and heavy-duty vehicles, the CEC found in its first Electric Vehicle Charging Infrastructure Assessment in July 2021.
The CPUC decision sought to address those needs through rebates for EV infrastructure.
“This decision adopts a long-term transportation electrification policy framework that includes a third-party-administered statewide transportation electrification infrastructure rebate program and directs the California electrical corporations, specifically, Pacific Gas and Electric, Southern California Edison [and] San Diego Gas & Electric … to jointly fund the program and associated activities,” the decision adopted Thursday said.
“The transportation electrification framework and rebate program further state policy promoting decarbonization and will continue to do so, as the supporting technology and policy mechanisms continue to mature,” it said.
In addition to the utility and ratepayer investments authorized by the CPUC, “billions of dollars in approved federal and state funds will support California’s [transportation electrification] infrastructure,” the decision said.
“As a result of the federal Infrastructure Investment and Jobs Act of 2021, for instance, California will receive $383 million in funding for [transportation electrification] infrastructure,” it said. “The act authorizes an additional $2.5 billion for ZEV infrastructure available in competitive grants nationwide.”
The CEC approved $1.4 billion for EV and hydrogen vehicle charging infrastructure over three years in November 2021.
And the past two state budgets committed a total of $10 billion to accelerate the state’s transition to ZEVs, with much of the funding dedicated to supporting medium- and heavy-duty fleets and disadvantaged and low-income communities. (See Calif. Governor Proposes Spending $10B on EVs.)
“California is leading the world in the zero-emission vehicle revolution, and this $1 billion investment will continue building out the state’s charging infrastructure to make the transition to electric vehicles easier than ever,” Gov. Gavin Newsom said in a statement following the decision.
“This complements the $10 billion package we enacted to build out the infrastructure and make it more affordable for Californians to make their own transition to electric vehicles, part of our overall $54 billion California Climate Commitment,” Newsom said. “These collective efforts are exactly how we will make our zero-emission transportation future a reality, cutting pollution and driving economic opportunity for Californians.”
New York transmission owners have proposed tariff amendments that would clarify their ability to exercise a right of first refusal (ROFR) for public policy transmission (PPT) network upgrade facility (NUF) upgrades identified in the interconnection study process.
FERC in March approved tariff changes that confirmed TOs could exercise a ROFR for upgrades that are proposed by other developers, but they lacked provisions on whether this applied to upgrades identified later by NYISO as necessary to reliably interconnect a project (EL22-2-001). (See FERC Approves ROFR for NY Transmission Upgrades.)
The Operating Committee on Thursday recommended that the Management Committee and Board of Directors authorize NYISO to file the proposed revisions, presented at the meeting by Stu Caplan, partner at Troutman Pepper, which represents the eight TOs.
In a statement to RTO Insider, Caplan said the proposed revisions would “merely apply a similar mechanism to upgrades that are identified in the interconnection process for the public policy transmission projects that are selected by the NYISO board.”
The revisions are the “logical extension of the process FERC approved in March of this year for upgrades identified at the project proposal stage,” he said.
Caplan told stakeholders that the proposal would replace a bilateral process that lacks certainty and timelines, provide for a transparent process that closely replicates approved standards, and define the ISO’s role in identifying which of the NUF components might qualify as an “upgrade” subject to a ROFR.
“It is the only current solicitation for a public policy transmission projects, and the first project that may result in the identification of upgrades in the interconnection process for a public policy transmission project,” Caplan said.
During Wednesday’s Business Issues Committee meeting — where the proposal was also presented — Howard Fromer, who represents the Bayonne Energy Center, asked whether NYISO had expressed support for the changes.
Caplan answered that the ISO has said the TOs are “free to carry this forward as a TO-led effort.”
This response was followed up by NYISO attorney Brian Hodgdon, who said that “nothing has jumped out as an immediate concern” to the ISO.
The proposed amendments now move to the Nov. 30 MC meeting for approval.
Winter Capacity Assessment
NYISO expects sufficient capacity margins for this winter but anticipates continued year-to-year declines as more fossil fuel generators retire.
The ISO told stakeholders that that they expect a total of 477 MW worth of generation to be deactivated and a total of 672 MW of new generation to be added during the upcoming seasonal assessment period.
SRIS Scopes Amended
The OC unanimously approved revisions to the system reliability impact study (SRIS) scopes for 35 generation projects, which the ISO identified as possessing evaluations that could either be removed, were redundant or could be conducted later.
NYISO had recommended that these previously OC-approved SRIS scopes be narrowed to expedite interconnection processes and streamline transmission studies (See NYISO Identifies 35 Projects for Narrowed SRIS Scope.)
Intermittent Resources Update
For the first time, NYISO shared the total nameplate value of installed intermittent power resources in the New York Control Area:
Land-based wind: 2,191 MW
Behind-the-meter solar: 4,123 MW
Front-of-the-meter solar: 74 MW
NYISO promised to expand this list to more intermittent resources, such as OSW, as they are installed in greater amounts, and promised to consider including battery storage in the future.
BIC & OC Elections
NYISO stakeholders unanimously elected Scott Leuthauser of Hydro Quebec Energy Services and Greg Yozzo of Central Hudson Gas & Electric as the new vice chairs of the BIC and OC, respectively.
[Editor’s Note: An earlier version of this article incorrectly attributed Brian Hodgdon’s quote to Brian Hurysz.]
FERC last week partially granted three complaints by SPP members alleging
the grid operator violated its tariff’s terms and
generator interconnection agreements (GIAs)
and engaged in unduly discriminatory and
preferential practices related to its revenue
crediting process under Attachment Z2 (EL19-75, EL19-96, EL19-93).
The commission, however, rejected a similar complaint from Oklahoma Gas & Electric (EL19-77).
EDF Renewables, Enel Green Power North America, NextEra Energy Resources and Southern Power filed a joint complaint in May 2019 under three sections of the Federal Power Act. They argued that they are entitled to revenue credits associated with transmission service that could not have been provided but for the use of network upgrades for which they paid.
Under Attachment Z2, SPP transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrades. FERC in 2020 approved the RTO’s request to replace revenue credits with incremental long-term congestion rights. (See FERC Approves SPP’s 2nd Go at Dropping Z2 Credits.)
The developers argued their companies had together funded, through their respective GIAs, almost $95 million in network upgrades owned by SPP transmission owners on the RTO’s system. The first of the upgrades became operational in 2010, they said, but SPP took until 2016 to add the software required for Z2, collecting charges for service that relied on network upgrades.
In their complaint, the developers pointed out that FERC said in a 2016 response to an SPP waiver request that the grid operator had already determined that they are eligible for revenue credits associated with their funded creditable upgrades.
FERC agreed with the complainants that SPP had violated the tariff, GIAs and the filed-rate doctrine, but it denied the remaining allegations. It also declined to set the proceeding for hearing and settlement judge procedures and to grant the developers’ requested relief, that being the full revenue credits and interest for transmission service SPP provided over the creditable upgrades since 2010. The commission said the underlying facts were “materially the same” as a D.C. Circuit Court of Appeals ruling in an OG&E complaint against SPP.
“We believe that exercising our authority under [Section 309 of the Federal Power Act] under these circumstances would be inappropriate for the same reasons,” FERC said.
FERC Commissioner James Danly agreed in a concurring statement to all four orders, writing that “FPA Section 309 cannot be invoked to provide equitable exceptions or retroactive modifications to the filed rate. … It is not a matter of discretion.”
The commission used the same arguments and reached the same decisions in complaints filed in September 2019 by Cimarron Windpower II.
It relied on some of those arguments in accepting and rejecting parts of Western Farmers Electric Cooperative’s August 2019 request that it be able to recover and retain revenue credits that it said it was entitled to under its network integration transmission service agreement and Attachment Z2. FERC found the attachment does not guarantee full cost recovery for network upgrades “but merely provides the opportunity to recover such costs.”
FERC rejected OG&E’s complaint, filed in May 2019, that being required to refund revenue credits related to the use of OG&E’s transmission facilities would violate Attachment Z2, the filed-rate doctrine, and the sponsored upgrade agreement between OG&E and SPP. The utility had also argued SPP must pay restitution if it required the revenue credits be refunded.
The commission responded by saying the upgrade agreement does not supersede the tariff, as OG&E suggested, because the agreement expressly incorporates the tariff. SPP does not have the revenue credits to provide as restitution to OG&E; those funds are with the transmission customers, who cannot be invoiced for credit payment obligations because of the tariff’s one-year billing adjustment limitation, FERC said.
SPP had been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)
The commission granted the grid operator a retroactive waiver of its tariff so that it could invoice transmission service customers for Z2 credit payment obligations dating back to 2008. However, it reversed course in March 2019, saying its original decision was prohibited by the filed-rate doctrine and the rule against retroactive ratemaking.
FERC in March 2019 issued a voluntary remand of the waiver following a D.C. Circuit ruling in a separate waiver case involving PJM. The court ruled in 2021 that the commission acted correctly in reversing the retroactive waiver. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)
A new study by National Grid suggests that states and utilities must move swiftly to equip the grid to support the travel needs of what’s expected to be an explosively growing segment of electric vehicles.
The utility (NYSE:NCG) this month offered an assessment of EV charger infrastructure needs, releasing a report on what the future might look like across its service area in New York and Massachusetts.
The report draws a buildout model of 71 charging plazas from westernmost New York to Cape Cod and forecasts they are each likely to have a peak demand of up to 5 MW by the early 2030s and up to 10 MW by the early 2040s.
As early as 2030, some of these sites will exceed delivery limits of the low-voltage distribution grid, the report predicted. But the main east-west and north-south routes where the 71 sites were envisioned overlap in many places with the high-voltage transmission system, the report said.
With bans on the sale of gas-powered light vehicles arriving in 2035, and with transmission and interconnection upgrades happening at a slow pace, the report flags the need to start building out EV charging infrastructure now.
Other factors will exacerbate the need, said Dave Mullaney of RMI, a nonprofit advocate for sustainability that contributed to the study.
“The Inflation Reduction Act will close the cost gap between diesel and electric trucks and create a surge of demand from buyers and investment from suppliers in the near future,” he said in a news release accompanying the report. “The biggest challenge to deploying those electric trucks will be finding the power to charge them. This study takes the first steps to overcoming that barrier and serves as a roadmap for the rest of the country to follow.”
The ratio of light- and heavy-duty battery-electric vehicles using a charging plaza will factor into its actual power needs, the report’s authors noted. Unknown factors such as the adoption of other zero-emission technologies also will determine how much charging capacity is needed.
The report notes that some projections show charging plazas drawing as much power as an outdoor pro sports stadium or small town when 20 or more fast chargers are in use simultaneously. The highest-demand sites could approach 40 MW of peak demand, as much as a major industrial site.
On-route charging will be part of an ecosystem to support electrical vehicles, along with chargers at homes, workplaces and truck depots. The National Grid report focuses on the site-specific impact of these highway charging stations rather than the regional, statewide or grid impacts examined in other studies.
The report offered six major takeaways:
A typical site will require more than 20 fast chargers.
Light-duty EVs will increase the power demand in the near-term but medium- and heavy-duty EVs will drive the increase in the longer term.
Managed charging and load management offer potential benefits, but many highway charging plazas will likely still require transmission interconnection.
A charging station’s proximity to transmission lines will drastically impact its construction cost and timeline and should receive the same degree of consideration as traffic volume, land availability and expected utilization in the siting process.
Any new electric infrastructure upgrade that is required should be scalable and suited to long-term needs; this will limit future duplication and cost.
Planning must start now for transmission and interconnections, because they can take four to eight years to complete while a new charger can be installed in a matter of months.
No Headroom
There is no way around transmission upgrades if the EV transition happens as envisioned, the report adds: The electrical grid as it exists does not have headroom for highway charging plazas.
And highway corridor charging is a key component of the EV transition. It will reduce range anxiety for drivers of light vehicles; supplement or replace depot charging for medium-duty trucks; and be indispensable for regional and long-haul operation of heavy-duty trucks, which have long and variable daily duty cycles.
To project the charging needs of light-duty vehicles, the study drew from more than 2.5 years of usage data at 3,000-plus direct-current fast chargers nationwide. Since no comparable data exist for large commercial trucks running on battery power, the study assumed they would operate the way internal-combustion trucks do today.
The authors also noted that the study did not factor in the negative impacts of cold weather on duration of battery charge, which might boost the demand for electricity, or the possible adoption of fuel cell technology in medium- and heavy-duty trucks, which might decrease power demand.
The study also did not adjust for holiday traffic or other limited circumstances when calculating peak demand.
An underlying theme in the report is that utilities such as National Grid should have a greater and more proactive role in planning the EV ecosystem, rather than assuming their historically reactive stance.
In the news release, National Grid’s chief operating officer for New York Electric, Brian Gemmell, said: “This kind of holistic, long-term infrastructure planning will be critical to delivering a clean energy transition as efficiently as possible. We have a responsibility to make smart investments that get it right the first time and to make sure the electricity is there when drivers need it. This study will help us do that.”
The PJM Markets and Reliability Committee endorsed an RTO-sponsored package to standardize variable operations and maintenance costs, with nearly 90% sector-weighted support.
An alternative measure from Constellation Energy — which would have removed nuclear unit refueling as VOM — did not receive a vote during Wednesday’s meeting. (See “Two Proposals Remain on Variable Operations and Maintenance Costs,” PJM MRC Briefs: Oct. 24, 2022.)
If accepted by the Members Committee, the language would create default adders for minor maintenance and operating costs as an alternative to generators submitting unit-specific information, and provide definitions of major maintenance and minor maintenance for more clarity on which costs fall into each.
The default adders would be calculated based on historical maintenance values provided to PJM and would be adjusted annually using the Handy-Whitman Index.
PJM accepted a friendly amendment suggested by Adrien Ford of Old Dominion Electric Cooperative to maintain the status quo for the submission deadline, rather than moving it to March as was originally written in the proposal when it was believed the RTO and the Independent Market Monitor would be reviewing submissions in succession rather than parallel.
Constellation’s Jason Barker said the company is in agreement with PJM on the key points of the VOM measure, with the exception of maintenance unique to nuclear units during planned outages, which he said can be scheduled up to three years in advance and does not vary with run time or number of starts.
Monitor Joseph Bowring said the costs of major maintenance shouldn’t be included in energy offers, and called the determination from PJM and FERC to do so a mistake, but he disagreed with the notion that nuclear generation should be treated differently from other resources.
Paul Sotkiewicz of E-Cubed Policy Associates said many resource types have the sort of time-based expenses Barker outlined and asked if he would accept a friendly amendment to expand the nuclear carveout to all time-dependent maintenance. Barker responded that the amendment was too large of a change to make on the fly.
The topic isn’t a “make-or-break issue for the nuclear industry,” said Alex Stern,= of Public Service Electric and Gas, but it does make the economics of operating a carbon-free resource harder.
“The country and the region have been spending a lot of time trying to figure out how to preserve zero-emissions generation like nuclear exactly because we need baseload generation as we move toward this changing generation mix, Stern said. “So there’s been a lot of customer expense being thrown at — properly so — trying to preserve reliable generation from nuclear. And I think that the concern here that Constellation is raising is that we’re throwing money at trying to make nuclear economic, but we’re going to take a step here that’s incorrectly putting costs on nuclear.”
Bowring responded that the PJM proposal does not impose any costs on nuclear or make any changes to the economics or margins for resource owners. Rather, it changes the markets to which the costs are assigned, not what they are. “For example, the Constellation proposal does not change the capacity market offer caps for nuclear units in any way. There is no good reason to exempt nuclear units from the rules that apply to all other units.”
Stakeholders Approve Quick Fix for Capacity Replacement Transactions
The committee voted to approve an issue charge and solution under PJM’s quick-fix rules to allow generators to replace capacity sold in a Base Residual Auction in years where there is only one Incremental Auction. The new language was approved by acclamation with two objections.
Michael Borgatti of Gabel Associates, representing Eagle Point Power Generation, said the current compressed timeline, in which there is one instead of three IAs each year, limits the opportunities for generators to engage in replacement resource transactions.
The revisions allow for capacity to be replaced if a “financially and physically firm commitment to an external sale of its capacity for the entire delivery year [has been] demonstrated with supporting evidence.” The changes are limited to currently scheduled delivery years during which there is only one IA scheduled.
Stakeholders expressed some reticence about the use of quick-fix rules to make the change, noting the possibility of those with objections not having adequate time to make their voices heard, but Borgotti said there is limited time to make manual revisions in time for the next auction date.
Bowring pointed out that for any resource facing the referenced issue of wanting to sell capacity outside PJM, there are defined steps in the tariff and in the manuals.
“This proposal provides an incentive to ignore the tariff rules about how to qualify for a must-offer exemption in the capacity market, to offer and clear and then to later withdraw the commitment to sell the capacity. That affects the market prices received by all other market participants,” Bowring said. “Approval of this proposal as a quick fix is effectively saying that any market participant that does not like the rules can come to the MRC at the last second and get the rules changed in their favor.”
Coal Resource Permitted to Enter Maximum Emergency for Fuel Shortages
Stakeholders also approved a manual change to allow coal generators to elect to enter into maximum emergency should their fuel stores fall below 10 days, effectively exempting them from the must-offer requirement while they rebuild their inventories. Facility owners can only make the voluntary determination to seek maximum emergency status from PJM should the fuel shortage be outside of their control and not the result of economic decisions.
PJM’s Chris Pilong said examples of legitimate issues beyond a facility operator’s control are mine fires, floods and tight supply chains. So long as those events are reported to PJM, it can examine whether permitting maximum emergency is warranted. The revisions passed by acclamation with no objections and one abstention. (See PJM Considers Changes to Max Emergency Status for Coal Plants.)
A facility cannot be granted maximum emergency status if PJM has issued a hot or cold weather alert or conservative operations, and the RTO can deny a request for any reason. A generator can remain under maximum emergency until it has reached 21 days worth of fuel inventory, if the owner elects to terminate the condition or if PJM issues one of the aforementioned conditions.
Bowring said there are legitimate reliability concerns related to coal inventories, but the responsibility of taking on and mitigating that risk should fall on the facility owners, not PJM.
“PJM is proposing a short-term fix that is unnecessary and is inconsistent with PJM’s stated objective of providing incentives for flexibility,” he said.
Susan Bruce, representing the PJM Industrial Customer Coalition, questioned if the markets are realizing the full benefits of coal resources if their inventories can’t be guaranteed and said there should be an oversight role to ensure owners are not managing inventories to be economically or physically withholding.
Because the changes were limited to manual revisions, only MRC approval was required, and the changes go into effect immediately.
TCPF Adjustments Permitted for Issues with Ongoing Solution
Stakeholders approved allowing PJM to modify the transmission constraint penalty factor (TCPF) in situations where the issues causing congestion are being addressed by in-progress Regional Transmission Expansion Plan projects. The revisions to the manual, tariff and Operating Agreement were passed by acclamation with one objection.
PJM’s Susan Kenney said the purpose of the penalty factor is to incentivize supply or load to address constraints through short-term solutions and develop long-term investments. When such investments are already underway and there are not feasible short-term solutions, applying the penalty factor may not make sense, she said.
Kenney noted the spark for taking a look at the functioning of the penalty factor came after one of three transmission lines into Virginia’s Northern Neck peninsula was put on outage for a planned upgrade in 2020.
The outage caused congestion into the peninsula, which pushed the TCPF to its default of $2,000/MWh in the real-time energy market. Because the completion of the upgrades would resolve the issue and it wouldn’t be possible for new generation to be added prior to the work being finished, PJM successfully argued to FERC that the design of the penalty factor created “unjust and unreasonable energy market rates” for consumers. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
A second proposal from the IMM would have broadened the criteria for adjusting the TCPF and used a different methodology to determine when to do so, but it received limited support and did not advance from the Energy Price Formation Senior Task Force. Bowring argued during the MRC’s first read of the PJM package that the proposal would allow the RTO to subjectively determine penalty factors and does not address why penalty factors are triggered so often. (See “MRC Discusses Transmission Constraint Penalty Factor Revisions,” PJM MRC Briefs: Oct. 24, 2022.)
1st Read on Proposal to Allow Flexibility for Market Participation During Defaults
PJM presented a first read of a proposal to grant flexibility for parties to continue participating in markets after a default under certain circumstances. The OA currently uses conflicting language regarding market participant involvement during a default, with some sections using “shall” and others saying “PJM may limit,” though Associate General Counsel Colleen Hicks said the OA generally uses mandatory language.
The factors that could warrant allowing continued market involvement are: grid reliability, the ability to generate revenues in the future and the ability to post collateral. A fourth consideration recognizes that certain transmission customers cannot have their service terminated without FERC approval and acts more as a clarification in the package under consideration, Hicks said. The proposal would also modify the tariff with reciprocal provisions.
Other Committee Actions
The MRC also passed with no objections:
proposed governing document changes to prohibit critical natural gas infrastructure from participating in demand response or price-responsive demand programs. The language was the same as the first read during the Oct. 24 MRC meeting. (See “Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented,” PJM MRC Briefs: Oct. 24, 2022.)
proposed tariff revisions that would require that financial transmission rights bilateral agreements to be reported to PJM with certain data within 48 hours of their execution. The primary economic term data that must be reported alongside the agreement includes the FTR start/end, quantity, source and price.
An anticipated vote on packages to create a “circuit breaker” that would limit extended price increases was deferred until the next MRC meeting to give sponsors time to work on the possibility of a compromise package. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)
PJM opened a poll on Friday to gauge support for dueling proposals to revise the rules for load behind-the-meter (BTM) of a co-located generator.
The two packages, the first jointly drafted by Constellation Energy and Brookfield Renewable Partners and the second from the Independent Market Monitor, largely differ in how they would account for the power being consumed by the load when determining how much capacity the generator can offer into the PJM markets. Under Constellation’s proposal, the facility’s capacity offer would not be reduced because the energy would remain available for PJM to call upon when needed, with the BTM load curtailed.
The IMM, however, argues that the power consumed by behind-the-meter load should not be counted toward the generator’s capacity offer. Its package would subtract the net peak load from the unit’s installed capacity.
Constellation Energy displays the envisioned configuration of co-located load, which would not be directly interconnected with the PJM grid. | Constellation Energy
Speaking during a Nov. 17 Market Implementation Committee special session to discuss the packages prior to the opening of the poll, Constellation’s Jason Barker said his company’s language would expand customer choice by providing options for companies whose loads are curtailable and don’t require the full services of the transmission grid.
“What we have seen is we have new large commercial customers that are choosing to locate highly interruptible loads behind-the-meter of generation resources, both to reduce their costs and ensure physical supply of carbon-free power,” he said.
Since the amount of power produced and consumed would remain the same regardless of whether the load is placed behind or in front of the generator’s meter, Barker argued that there would be no impact on prices. The arrangement would also allow for the behind-the-meter to rapidly be curtailed and that power shifted to PJM when LMPs exceed the facility’s market offer, or when called upon by the RTO.
“The response time is the same as a [synchronized] reserve product. And I highlight for all of the folks on the call that we have many, many, many capacity resources that provide capacity commitments today for which their energy is callable not in minutes, but in hours or in some cases even days. So this is a superior product to most of the capacity commitments you’re getting in that respect,” he said.
PJM’s Independent Market Monitor Joe Bowring told the MIC that even if capacity prices remain unchanged, allowing generators to sell a portion of their energy to behind-the-meter customers while keeping that output in the capacity market would effectively reduce the amount available to PJM and send incorrect incentives to the markets about the amount of additional capacity needed to maintain reliability.
“The Constellation proposal is to sell the capacity twice, once to the behind-the-generator load and once to PJM customers,” he said
“What this is really doing when you think about it is taking a resource which is providing low-cost energy, 8760 [hours a year], and providing energy for a small number of hours a year. … That will create potentially very significant issues, depending on the level of the megawatt hours taken off the system,” he said. “Removal of this level of energy inputs at key points in the transmission system that was designed around these units would have extremely significant impacts on the grid. PJM should provide analysis of the impacts. PJM’s analyses to date do not address the real issues, including the combined impact of multiple such requests.”
Bowring said the rules need to be finalized before investments in the behind-the-meter load configurations under discussion start coming in, calling Constellation’s proposal a “sea change.”
To date, PJM has received requests to add 4,469 MW of co-located load behind-the-meter of 18 existing generation units, with a combined installed capacity of 15,800 MW. Of the new load requests, 3,906 MW is proposed to be configured to receive power from the generator without being interconnected to the PJM grid.
“The IMM’s approximate calculations show that removal of 20,000 MW of low-cost energy could raise energy costs for other customers by billions. There is no indication that the referenced loads would join PJM in the absence of the proposal. If the loads did join PJM, they should follow the same rules as all other load,” Bowring said. “There are current provisions for interruptible load that would address the stated goals.”
Studies have been completed for 864 MW of the co-located load requests, which are being treated as amendments to the generators’ existing interconnection service agreements under the existing rules, said Augustine Caven, PJM’s manager of infrastructure coordination.
Jurisdiction Over Co-located Load Disputed
The MIC also debated the issue of whether co-located load falls under federal or state regulation at the Nov. 17 meeting. Several stakeholders argued that such loads receive the benefit of synchronized reserve, regulation and ancillary services through the generator’s interconnection to the PJM grid, even if the load is not directly interconnected itself.
PJM Senior Counsel Chen Lu, who presented the RTO’s perspective that co-located load is state regulated, said during the Oct. 13 MIC special meeting that the issue is similar to the question of power consumed by generators.
“To me this really isn’t that different from the station power cases that FERC has decided. And in those cases when a generator is receiving station power, they may still be benefitting from the grid. But FERC has explained since those are not sales for resale, they weren’t FERC jurisdictional and those are ultimately state jurisdictional retail sales. And so just by virtue of the fact that they may have some benefit from the grid, doesn’t necessarily make it FERC jurisdictional,” he said.
PJM Director of Market Settlements Initiatives Lisa Morelli said a logical extension of requiring co-located load to pay for services such as synchronized reserve would be that generators could also then be required to pay that as well.
“I think if you continue pulling that thread, that is where you would land,” she said.
The Bonneville Power Administration last week proposed to hold key power and transmission rates mostly flat over its next two-year rate cycle — and said it might cut rates this year — in light of a “strong” financial performance over the past 12 months.
The federal power marketing agency said steady rates will provide a “buffer against market volatility” for its customers, which largely consist of publicly owned utilities across the Pacific Northwest. Those utilities serve residents with some of the cheapest power in the U.S., most of which is generated by the region’s extensive network of hydroelectric dams.
“This is one of those bountiful years where all the elements and timing came together in such a manner that we can consider staving off inflation for another two years by keeping rates flat for our power and transmission customers,” BPA Administrator John Hairston said in an announcement Friday.
The agency said it earned $964 million in net revenues during fiscal year 2022, far outdistancing its target of $172 million.
“Each quarter, we have signaled our expectations that Power and Transmission were expected to have a solid year, and I’m happy to report that was in fact the case, with both business lines significantly beating net revenue targets,” Marcus Harris, BPA’s acting CFO said in a press release Thursday.
During its quarterly business review on Wednesday, the agency said it would consider using its financial reserves to reduce rates in FY 2023, which began Oct. 1.
Friday’s announcement kicked off the formal process for BPA’s power rate case (BP-24) and transmission rate proceeding (TC-24) for fiscal years 2024/25 (Oct. 1, 2023 to Sept. 30, 2025). Agency staff will officially publish initial proposals for the new power and transmission rates on Dec. 2, the same day as a pre-hearing conference to discuss the plans, but both plans are already available online. The proposed rates were the subject of a series of stakeholder meetings held this summer.
BPA’s power rate schedule consists of four categories of primary rates for federal energy sales, including the:
Priority Firm Power Rate (PF-24), or “Tier 1,” which applies to firm power sales to BPA’s public body, cooperative and federal agency customers;
New Resource Firm Power Rate (NR-24), which applies to firm sales to investor-owned utilities and public customers serving new large, single loads. (BPA is forecasting no sales at this rate during the BP-24 period);
Industrial Firm Power Rate (IF-24), which is applicable to firm power sales to Direct Service Industrial customers; and
Firm Power and Surplus Products and Services Rate (FPS-24), applicable to “sales of various surplus power products and surplus transmission capacity for use inside and outside the Pacific Northwest.”
Tier 1 “non-slice” contracts represent the majority of BPA’s power sales. “Non-slice” refers to a type of contract in which the customer is guaranteed a specified volume of energy regardless of conditions on the hydro system; in contrast, total volumes delivered to “slice” customers can vary based on availability.
In a notice filed in the Federal Register on Friday, BPA said non-slice rates will remain flat at an average rate of just under $35/MWh. But when slice rates are considered, average Tier 1 prices should actually decline slightly, according to the notice.
“The individual experience — slight increase/decrease/flat — of customer utilities will vary based on what products they use and the ways in which they use them,” BPA spokesperson Kevin Wingert told RTO Insider in an email.
In the notice filed Friday, BPA said it expects to sell power to only one industrial customer at the industrial rate over 2024/25, but that customer can expect to see significantly higher costs during the most energy-constrained months, with December prices rising from $51.99/MWh to $63.40/MWh, and August rising from $49.10/MWh to $73.29/MWh. That is in part a reflection of changing expectations for river flow patterns in the Northwest — as well as summer cooling needs — caused by climate change.
BPA’s proposal would extend current transmission rates unchanged into FY 2024/25, with “main grid” and “secondary system” — or lower-voltage — charges remaining at $0.0774/mile and $0.76/mile, respectively.
The agency operates about 15,000 miles of transmission, about 75% of the system in the Northwest.
