A panel of energy experts took ISO-NE’s capacity market to task last week, lambasting the region’s Forward Capacity Market and offering ideas about how to improve it.
The panel at the Northeast Energy and Commerce Association’s Power Markets Conference, held Dec. 5, was titled “Can Markets Get Us More Reliable?”
And while the answer from the group wasn’t an unconditional “no,” it involved heavy criticism for the way the capacity market is currently set up.
“I’ve always viewed forward capacity markets as the original sin of market design,” said William Hogan, a professor of global energy policy at Harvard University.
“I know it’s politically embedded in the system … but I don’t think they’re a solution to any real problem other than mailing checks to people,” Hogan said.
When it comes to ISO-NE’s markets specifically, Sheila Keane, director of analysis at the New England States Committee on Electricity, said that there’s a lack of a “clear measurement or goalpost” for energy adequacy.
“If we’re thinking about changes to the capacity market, that’s something the states are always open to having discussions [about],” she said.
David Patton, president of Potomac Economics, ISO-NE’s External Market Monitor, said the FCM isn’t a viable solution to most of the problems that New England’s grid faces.
“It’s not a very good solution for resource adequacy to begin with, but when you start to look at some of the challenges we’re facing with reliability and the introduction of intermittents, it becomes less and less reliable,” he said.
And Ben Griffiths, regulatory policy director at LS Power, rounded out the critique with an academic bent.
“On the capacity market side, there is not enough liberal arts thinking,” he said. “It’s not clear to people what they’re actually buying, or what [the 1-day-in-10-year loss of load standard] is actually doing.”
DERs and Blurred Lines
On a later panel, titled “Blurring of Wholesale and Retail Lines,” experts laid out the importance of distributed resources for the energy future, and of markets and pricing that help incentivize them.
Greg Geller, head of regulatory affairs at Enel North America, laid out a bevy of benefits from greater DER utilization in New England, including reduced transmission costs, better price signals for emissions reduction, help with winter reliability issues and more.
But to do that, the region needs strong and flexible retail programs, the panelists said.
Part of the challenge is that different entities regulate overlapping spaces, said Caitlin Marquis, director of Advanced Energy Economy.
That’s been demonstrated by the compliance process for FERC Order 2222, which requires RTOs and ISOs to provide DERs access to wholesale electricity markets.
“The compliance directive was on the ISO, not on the states or retail regulators — but they have an important role in implementing pieces of Order 2222,” Marquis said.
ISO-NE is thinking carefully about how to integrate demand resources in the region, said Henry Yoshimura, the grid operator’s director of demand resource strategy.
“What do we need? Retail rates that reflect time-varying costs,” he said.
“Retail prices should be high when marginal costs are high and should be low when they’re low,” Yoshimura added.
Without the right rate design, he said, “you’re never going to get the right demand flexibility” from DERs and other such resources.
NYISO is qualifying generation units for meeting their reserve requirements even though they fail to provide adequate reserves during normal market operations, the ISO’s Market Monitoring Unit told stakeholders Tuesday.
Speaking to the Installed Capacity/Market Issues Working Group, Potomac Economics’ Pallas LeeVanSchaick said NYISO is using capacity accreditation rules that may be awarding excessive accreditation to several gas generators. The ISO should re-evaluate its reserve auditing procedures for gas turbines to be more responsive to normal market operations and improve capacity accreditation test requirements to account for peak summer conditions, he said.
The Monitor’s third-quarter report on the NYISO markets, released last month, found that the ISO is conducting more 10- and 30-minute non-synchronous reserve pick-up (RPU) audits but has failed to disqualify gas turbines that performed poorly.
Gas turbine audits show inability to accommodate normal reserve requirements. | Potomac Economics
Potomac studied the 13 worst performing gas turbines; despite many of them being consistently used by the ISO, they regularly fail to achieve performance levels even close to the 89% average of all other gas turbines.
Kevin Lang, partner at Couch White, asked why Potomac believed the ISO was not acting on generators that had performed poorly in audits.
LeeVanSchaick responded that “NYISO has the authority to do that … but it is not clear to us why they have not been disqualified.” Potomac will “monitor this because there’s inefficiency in continuing to compensate resources for providing reserves when they cannot perform.”
According to the report, on days when peak load surpasses 28 GW, an average of about 1,060 MW of installed capacity from fossil fuel and nuclear generators was functionally unavailable during the quarter because of above-average temperatures.
Functionally unavailable capacity from generators during peak conditions | Potomac Economics
Emergency generators dispatched by NYISO during peak load may overestimate their available capacity and receive improper accreditation because these units’ dependable maximum net capability (DMNC) tests, which calculate the gross sustained net output of a generator, fail to capture ambient water temperatures, LeeVanSchaick said.
The audit results suggest “that there is a tendency to over-credit resources that are impacted by ambient conditions,” he said. On peak summer days, “there is capacity that, although qualified, is not as effective as other capacity in terms of providing reliability,” meaning “some units are going to be less available at peak times.”
Howard Fromer, who represents the Bayonne Energy Center, asked whether Potomac had begun discussions with NYISO to adjust capacity accreditation procedures or rules for the impacted resources.
NYISO energy markets were competitive throughout the quarter, according to the report. Energy prices increased across all zones because of both higher congestion in the Central-East interface and emissions costs, and capacity prices fell because of lower installed reserve margins and peak load forecasts, which helped offset increased spot prices.
Washington Gov. Jay Inslee said Monday he will seek millions in state funding to establish a program at Washington State University’s Tri-Cities campus dedicated to researching sustainable energy.
Inslee said he plans to ask the state legislature in January for $10 million to fund the Institute for Northwest Energy Futures at WSU’s Richland branch.
The work to launch the institute began last year when a now-deceased longtime supporter of the school donated $500,000 toward an endowment to fund the salary for the director of the institute. No other donations have since followed, Chris Mulick, WSU director of state relations, told NetZero Insider.
With funding from the state, WSU would likely lease a building near the Richland campus for the institute, Mulick said. The institute plans to hire a director in its first year, and scientist faculty members in the second year after legislative approval.
The faculty would be split with five at the Richland campus and three at WSU’s main campus in Pullman. Each faculty member would have a graduate assistant. Some ancillary employees would also be hired. The Richland campus currently has about 100 faculty members.
Of the $10 million, $2 million would go into an endowment to pay the salary of the institute’s yet-to-be-hired director.
“I’m cautiously optimistic about legislative support for this idea,” Inslee said at a press conference in Richland.
Richland is also home to the Pacific Northwest National Laboratory, the Hanford nuclear reservation and many small engineering and research firms. Consequently, Inslee believes the city is good place for the institute to interact with Richland’s huge scientific and engineering community. The area is also home to research on nuclear, solar, wind and other alternative types of power.
“There is no one technology that we’re going to bind ourselves to as the exclusive game in town,” Inslee said.
Devin Hartman, R Street Institute | R Street Institute
By Devin Hartman and Kent Chandler
For more than a year, FERC, state authorities and industry stakeholders have agonized over the performance of transmission planning. The most notable forums include the Joint Federal-State Task Force on Electric Transmission and FERC’s October 2022 technical conference.[1],[2] The only reform action to date has been a Notice of Proposed Rulemaking on regional transmission planning issued by FERC last April, with a final rule in sight for early-to-mid 2023.[3]
These processes have revealed troubling flaws in transmission federalism. Moving forward, three principles should guide transmission planning reform:
Durability. Reforms must be legally and politically robust to secure a stable regulatory climate.
Quality governance. Local and regional transmission planning are co-dependent, meaning they require synchronization between state and federal regulators with clear roles and responsibilities for each. Proper transmission planning also requires independent administration and monitoring.
Sound economics. Planning should be proactive, incorporate all technological solutions, and maximize net benefits to consumers. Procurement should be competitively bid wherever possible and regulatory scrutiny should fill in gaps where competition is unworkable.
Current transmission planning does not embody these principles. The consequences are higher-than-necessary costs, stifled innovation, diminished reliability and prolific controversy. FERC Commissioner Mark Christie recently observed that transmission capital expenses have nearly tripled between 2012 and 2020.[4] Feeling this pain, dozens of consumer groups have called for better governance, planning and competitive procurement.[5]
Repairing Current Frameworks
The economic disappointment and extensive controversies surrounding transmission development should come as no surprise: They directly reflect the institutions and policies underlying transmission planning and procurement. FERC Orders 890 and 1000 have good bones, but framework adjustments along with fixing key implementation flaws are paramount. For example, the same rules ostensibly exist regardless of regional transmission organization (RTO) membership, but two sets exist in practice — one in RTO regions and another outside them — creating untenable governance issues.
The current regional transmission framework is reactive, miscounts transmission benefits, excludes some technologies from consideration and plans economic and reliability projects in artificial silos. Astoundingly, a large proportion of transmission development is neither subject to competitive bidding nor economic regulation. Competitive exemptions are too frequent in RTO footprints, while competition is non-existent outside RTOs.
Where competition is absent, gaps in regulatory oversight remain pervasive. FERC’s formula rates for transmission, coupled with the presumption of prudence, is not economic regulation. Meanwhile, not many states have full authority to approve or review transmission projects, and even fewer state commissions play a meaningful role in the planning of transmission facilities.[6] Projects in the 100-230 kilovolt (kV) range, those creatively dubbed “reliability need,” or those within a single transmission zone, regardless of cost allocation, often fall between the cracks.
In Order 1000, FERC declined to remove a federal right of first refusal for local transmission, out of consideration for incumbent utilities’ retail “service obligation.” However, since Order 1000, billions of dollars of local transmission have been built by affiliates of incumbents, without having a service obligation themselves.[7] These projects are exempt from competition. State utility commissions have little-to-no jurisdiction over them. And their costs are often allocated across state lines.
Further, it is hardly fair to consider transmission between 100 and 230 kV “local” given the increasingly regional nature of those facilities. Between February 2020 and July 2022, the Kentucky Siting Board approved certificates for 20 merchant solar facilities, between 40 and 250 MWs), with an average size of more than 100 MW.[8] All of the projects propose to build or connect to transmission below 200 kV, and only one-fifth of the projects are being built to provide power to Kentucky utilities, while the rest will serve customers across the Tennessee Valley Authority, MISO and PJM footprints.
At above-market rates of return, it is no surprise that incumbent utilities have prioritized building out transmission where competition and regulatory oversight are virtually absent. In doing so, they typically pursue inefficient small projects in lieu of more efficient technologies and subvert the planning of more efficient alternatives at the regional level.[9] In some regions, the majority of transmission projects skirt competition and robust regulatory review, and the number is growing.[10]
Repairing all this requires governance and economic reforms to work in tandem, augmented by stakeholder buy-in. Three reform priorities are:
Improve the Order 890 and 1000 frameworks. Equalize the application of Orders 890 and 1000 across RTO and non-RTO regions. All regional transmission should be independently planned. RTOs provide this function, but accomplishing this objective outside RTOs would require an independent transmission planner. Regional transmission planning must account for public policy effects on generation, including anticipated retirements based on plant economics, and not wait for deactivation notices to be submitted.
Make regional transmission planning proactive and holistic with enhanced competition. Planning should reflect the multi-decade nature of the investment, incorporate commercially available technologies, and account for the full suite of economic and reliability benefits simultaneously, not in silos. Minimizing competitive exemptions is crucial, with options including stricter “reliability need” exemptions and lowering the voltage exemption threshold to 100 kV to comport with the standard definition of the bulk power system.[11] This would clarify for states the scrutiny that some projects undergo.
Ensure economic oversight where competition is unworkable. Utility projects exempt from competition must face economic scrutiny from regulators, which warrants reexamining the policy of unconditional formula rate treatment under a presumption of prudence. Need and prudence are impossible to judge without information. State regulators note that an independent transmission monitor (ITM) could furnish such information and help close the regulatory gap with local transmission projects.[12] It could also help ensure Order 890 compliance.
Reform Agenda
Transmission reforms are as entangled as the bulk power system. Yet many reforms will be pursued through disparate procedural vehicles, which elevates coordination risk.
FERC’s first bite at the apple is its forthcoming final rule on transmission reform. The winning formula is for FERC to jettison the anti-competitive provisions of its proposed rule while refining the good ones, including the longer-term planning horizon, what advanced technologies to include in planning, holistic benefits accounting and breaking down silos between “economic” and “reliability” project planning.[13]
FERC will need to pursue the remaining reform agenda through separate proceedings. The October technical conference established a record upon which to prioritize governance improvements, including the role of independent monitoring and planning, as well as pathways to expand competition and close the regulatory gap for projects where competition is unworkable. This could spin off into any number of dockets. The trick will be connecting the dots.
Devin Hartman is director of energy and environmental policy for the R Street Institute.
Kent Chandler is the chairman of the Kentucky Public Service Commission.
The results of more than 60 years of effort at a federal laboratory charged with ensuring the reliability of U.S. thermonuclear weapons could give the nation the ultimate weapon to fight climate change with a technology capable of producing carbon- and radiation-free energy.
White House and defense policymakers joined Energy Secretary Jennifer Granholm on Tuesday and a research team from Lawrence Livermore National Laboratory to provide a few details of the technology that researchers developed to pull off a global first: less than one second of controlled hydrogen fusion that created more energy than had been required to initiate it. (See related story, DOE to Announce Major Advance in Fusion Technology.)
That’s the same kind of reaction that powers stars, including the sun. And it’s the same physics at the heart of a hydrogen bomb.
“We got out 3.15 megajoules. We put in 2.05 megajoules in the laser,” explained Marvin Adams, Texas A&M nuclear engineering professor and deputy administrator for defense programs at the Department of Energy. “That’s never been done before in any fusion laboratory anywhere,” he said in a detailed panel discussion that followed the official announcement.
The experiment involved focusing the light of powerful lasers on a tiny capsule suspended inside a glass cylinder. The capsule, about the size of a peppercorn or half a BB, contained isotopes of hydrogen. The force of the lasers, which had been converted to X-rays, compressed the hydrogen isotopes to the point at which they merged, releasing the energy in the form of heat.
The entire experiment — energizing 192 of the most powerful lasers on the planet — required more than 300 megajoules, said Adams.
That meant that powering up the lasers took a little over 83 kWh of electricity — not exactly an energy hog, but still far more power than produced in the small capsule in which the fusion occurred. In 2021, the average monthly residential power consumption was 886 kWh, according to Energy Information Administration.
“The laser wasn’t designed to be efficient,” Adams quickly added. “The laser was designed to give us as much juice as possible to make this incredible condition possible in the laboratory. There are many, many steps that would have to be made in order to get to inertial fusion as an energy source.”
Granholm noted that the Biden administration’s goal is to develop a commercial fusion reactor within 10 years. “This demonstrates that it can be done,” she said. “That threshold being crossed allows [researchers] to start working on better lasers, more efficient lasers, on better containment capsules — the things that are necessary to allow it to be modularized and taken to commercial scale.”
The strategy at LLNL has been based on using the powerful lasers not only to jumpstart fusion but also to control the reaction after it has begun with the pressure of the beams themselves.
The resulting “inertial confinement fusion” not only relies on the pressure of the laser beams to force hydrogen isotopes close enough together to initiate the fusion but also to confine the resulting explosive results in order to create conditions for a controlled but continuous fusion.
The fusion produces enormous amounts of heat that could be used to produce steam to power turbines and generators just as commercial fission reactors operate today.
There are several private research and development companies that are working to develop fusion reactions controlled by extremely powerful magnets rather than the force of lasers. California-based TAE Technologies has developed fusion experiments creating and magnetically controlling 135 million-degree plasma. (See TAE: Fusion Reactor Controls 135M-degree Plasma.)
TAE’s goal is to build the hardware and a process to produce 180 million-degree plasma, the point at which fusion can continue, again controlled by ultra-powerful magnetic fields.
General Fusion, a Canadian company, earlier this week announced it had achieved a milestone: controlling the superheated plasma with compression alone for brief periods rather than with magnetic fields or lasers.
LLNL Director Kim Budil said the competing technologies will “feed off each other” in the future. “Many technologies will grow out of both fields in addition to the path to a fusion power plant. I think having both [technologies] is important.
“If we could not ignite capsules in the laboratory, you could not see a pathway to an inertial confinement fusion energy plant,” she said. “So this was a necessary first step.” She noted that the laser array at the lab “was built on 1980s laser technology.”
“We need to bring modern technology approaches to the drivers. We need to think about all the system questions.”
AES Ohio (NYSE:AES) presented the PJM Transmission Expansion Advisory Committee on Dec. 6 with a $145.1 million supplemental project to build two new substations and 13 miles of double circuit 345-kV lines to meet over 1,000 MW in expected load growth from electric vehicle manufacturers in the Jeffersonville area. The area is currently only served by a radial 69-kV extension.
The proposed solution would expand the planned $27 million Madison substation, which is to be built along the Green-Beatty 345-kV line, with a new 345-kV substation. The expansion would step down to 69 kV to feed into the South Charleston substation and also have four 345-kV line exits.
The Fayette Substation would become the primary source for the region, stepping down from 345 kV to 138 kV and 69kV. It would include a quarter-mile 138-kV extension to serve a 140-MW committed development. It is estimated to cost $33.9 million. Adding 13 miles of double circuit lines to connect it to the Madison substation would cost an estimated $51.2 million.
“This substation is located central to the largest developing load center in the AES Ohio area supporting the electric vehicle manufacturing industry developing in the area,” the AES presentation says.
A 69-kV line from the Fayette substation would run approximately 1.5 miles to the new Panther substation, which is proposed to replace the existing Jeffersonville 69-kV substation — which is located in a floodplain and impractical to expand any further. The new substation, designed as a “69-kV breaker and a half station” would step down to 12 kV.
The Panther substation comes with a projected $15.5 million cost, while the 69-kV line and rerouting around 5.5 miles of lines from Panther to the existing Octa substation, which was previously connected to the Jeffersonville substation, is estimated to cost $17.5 million.
The project would add to an existing supplemental project, S0323, that would construct a 69-kV line from South Charleston to Jeffersonville. AES said the expected load exceeds the capabilities of that line.
Other Supplemental Projects
PECO (NASDAQ:EXC) has proposed to upgrade obsolete relays, communication and metering equipment, as well as remove a wave trap on the Heaton-Jarrett line in Montgomery County, Pa. The estimated cost is $1.77 million with an in-service date of April 1, 2023.
Dominion Energy (NYSE:D) has identified three facilities with low voltage issues caused by a contingency with the loss of two lines in Norfolk, Va.
Dominion submitted a distribution point request for a new substation, which would be named Edsall, servicing a total load of approximately 100 MW in Fairfax County.
Dominion also submitted a request for a distribution request for a new substation, to be named Tropical, serving a data center campus with a load over 100 MW in Henrico County. The requested in-service date is Jan. 1, 2025.
Generator Deactivation Update
PJM has determined that there are no reliability concerns associated with a deactivation request from a 14-MW Lorain County landfill facility, which has requested to go offline on April 1, 2023, according to Phil Yum of PJM’s system planning modeling and support department.
ALBANY, N.Y. — The New York Climate Action Council (CAC) met Dec. 5 for its penultimate meeting to discuss the final edits to its scoping plan and debate both labor unions and hydrogen resources.
Hydrogen was the most contentious topic at the meeting, with members upset by the inclusion of “low-carbon-intensity” hydrogen as a sustainable form of hydrogen, alongside green hydrogen.
Robert Howarth, professor at Cornell University, the term is “deceptive” and essentially a way of including blue hydrogen in the plan without actually using that term.
While green hydrogen is produced from water split via renewable-powered electrolysis, with oxygen as its only byproduct, blue hydrogen is produced from splitting methane (CH4), with the emitted carbon captured and sequestered. Opponents of blue hydrogen — among whom Howarth is a leader, having authored a paper against it with Mark Jacobson — argue that the process does not result in net-zero emissions, as the methane used is produced from natural gas.
Howarth argued last week that the inclusion of “low-carbon-intensity” hydrogen would enable the “marketing campaigns of the oil and gas industries” to use the CAC’s plan “to argue for the continued use of fossil hydrogen downstream in New York.” Howarth said the council should be “unambiguous when we send messages to the public, politicians and press.”
Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University, agreed that the concept of hydrogen “was once clear [but] is now quite cloudy,” arguing that the CAC has not investigated blue hydrogen and that “lumping” it with green hydrogen is inappropriate.
Raya Salter, executive director of the Energy Justice Law and Policy Center, said the revisions run “absolutely counter” to the CAC’s work and “look pro-fossil fuel industry.” She said it was “shocking” that “the door had been opened to blue hydrogen.”
Mario Cilento, president of the New York AFL-CIO, expressed support for the inclusion of blue hydrogen because “improving reliability, mitigating against extreme cost increases, avoiding job losses and creating job opportunities” was critical to the success of the scoping plan.
New York Public Service Commission Chair Rory Christian disagreed with members’ characterizations of “low carbon intensity,” saying that the term “blue hydrogen” did not appear anywhere in the current scoping plan and that the language “adequately addresses the concerns raised” while still acknowledging that hydrogen has many potential roles to play in energy generation.
‘Family-sustaining’ Union Jobs
Edits to the “Just Transition” chapter of the plan added language recommending that the jobs created be “good, family-sustaining, union” jobs.
Shepson was confused by the added language, saying it sounded like “part of political slogan.”
Cilento responded that the intention was to emphasize that union jobs tend to have better wages and conditions than non-union jobs. Furthermore, a union workforce would be better positioned to help New York, and “it is easier to sustain a family on union wages than not,” Cilento argued.
Shepson, who said he is supportive of unions, replied that “his non-union [job] has been family-sustaining.” He argued that as currently written, the plan appears to imply that only unions can create worthwhile jobs and that the state’s explicit policy is to only support unions.
Elsenbeck was also confused by the language, saying that, although also supportive of labor unions, it was important to encourage jobs in all their forms and that most of the industry workers he interacts with are not in unions.
The CAC will vote on the final scoping plan on Dec. 19, and council members will also be given an opportunity to share any last statements.
The plan will be formally adopted if it receives a two-thirds supermajority approval vote from the CAC. It would undergo an evaluation assessment at least every four years.
A poll by the Market Implementation Committee last month found little support for two competing proposals on capacity offer opportunities for co-located load — one from the Independent Market Monitor and the other a joint package from Constellation Energy and Brookfield Renewable Partners.
Given the opposition, which comments from the poll suggest cut to the core of the packages, stakeholders last week agreed it would be best to focus on finetuning and clarifying how co-located load not directly interconnected with the grid is treated under the status quo rules. (See PJM Opens Poll on Co-Located Load Proposals)
Currently, generators serving customers who are solely connected to their supply must relinquish a portion of their capacity interconnection rights (CIRs) equal to the amount being provided to the co-located load.
The Constellation/Brookfield proposal, which received 16% support overall, would have allowed generators serving such customers to retain their CIRs in exchange for the generation capacity remaining available to the grid when called upon — essentially turning the portion of generator serving the co-located load into a peaking unit. Constellation’s Jason Barker said during last month’s special session that the imagined arrangement under the proposal would be a nuclear facility supplying power for highly interruptible load, namely hydrogen electrolyzers.
Poll respondents said they believed that not requiring co-located load to pay for benefits received from the grid — such as synchronized reserve and scheduling — would leave other interconnection customers with having to pick up the cost. Commenters also said the arrangement would effectively allow generators to sell their capacity twice. Those in favor of the proposal said it could prevent generator retirements and the resulting increase in capacity prices and decrease in reliability.
The IMM package would have followed the existing practice of requiring generators to reduce their capacity offer equal to the power draw from the co-located load, while also levying additional charges on the load and administrative requirements on the generator. The proposal received 8% support overall and 9% against the status quo.
Commenters on that plan said they wanted additional details on cost allocation and answers to jurisdictional questions on how the provisions could be implemented. They also expressed concerns about potential overreach into areas addressed by reliability studies. Some respondents said they preferred the package’s stronger accounting for benefits received by co-located load.
Monitor Joe Bowring said the poll results suggest PJM should discontinue discussion of the two proposals and instead focus on clarifying the existing rules. Stakeholders largely agreed Wednesday that co-located loads will continue to exist and that the rules governing their relation to the grid should be clarified.
“While Exelon and other stakeholders are not supportive of the two options on the table, we do think that there would be value in potentially clarifying the status quo rules,” Exelon’s Sharon Midgley said.
Manual Revisions for Day-ahead Zonal Load Bus Distribution Factors Endorsed
The MIC endorsed by acclamation a package modifying how PJM conducts its day-ahead load bus distribution factor analysis and associated manual revisions. The changes still require approval by the Markets and Reliability and Members committees, which will likely vote on them during their January and February meetings.
Under current practice, the RTO calculates the hourly distribution factor for an individual node based on the percentage of state estimator load for that node as of 8 a.m. the prior week. For example, when building estimates for the July 14 market day, data from July 7 at 8 a.m. is currently used for every hour throughout the day.
Under the proposal, distribution factors would be calculated based on real-time data from each hour of the respective weekday of the previous week. So, when looking at 5 p.m. on July 14, data from the corresponding real-time interval on July 7 would be pulled.
The lookback period would use the most recently available day of the week where all 24 hours of data are available, meaning if one hour of data was unavailable for a day in the previous week, data would be drawn from the week before that.
Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling
PJM will be revisiting a proposed issue charge and problem statement on modeling combined cycle units in the market clearing engine to incorporate stakeholder concerns about potentially making market design changes to resolve issues with the scale of the computational challenges.
Concerns raised during the first read of the documents include whether it’s more appropriate and feasible to find a hardware or software solution to the issue, the potential for market power rules to be watered down by switching from multiple schedules per facility to one, and the broad scope of the issue charge.
The current design of the market clearing engine looks at each schedule a generator offers into the energy market as a separate logical resource. While most resources have either one or two, it’s possible for the number to be much higher — particularly for combined cycle units — which exponentially increases the solution time. The problem statement says that a typical 2×1 combined cycle unit would have at least six configurations, meaning that if it offers two schedules into the market, it would be represented by 12 logical resources.
“Based on the last several years of experience with a multi-schedule model in the current MCE and discussions with GE, it is apparent that the multi-schedule model in the MCE with the ECC model will have a significant performance impact that will jeopardize the clearing of the day-ahead and real-time energy markets in the approved clearing timeframe with sufficient accuracy,” the document says.
Paul Sotkiewicz, of E-Cubed Policy Associates, questioned why PJM could not increase its computational capabilities with additional hardware or by using algorithms that can cut down on the number of branches the engine has to compute.
“I don’t think PJM has exhausted nearly all the venues and possibilities, including talking to others who may be more up to date on the more advanced algorithms that are out there,” he said.
Sotkiewicz was also “alarmed” that PJM is seeking to potentially make market design changes with an envisioned six-month timeframe to meet the requirements of a vendor hired without consulting stakeholders. PJM’s Keyur Patel said GE has been hired to develop a market engine product for combined cycle modeling — work it is engaging in concurrently with other RTOs — and aims to begin its PJM work by the end of next year, assuming associated rules have been approved by then.
Patel said PJM re-examines hardware requirements every three to four years and does not believe that hardware or algorithm changes would be enough to resolve the issue.
“There is no other technology available at this point that we can solve it in two hours or [a] two-and-a-half-hour time frame,” he said.
Bowring said the use of multiple schedules for each generator was implemented to provide greater market power protections and that it would be a mistake to revert that change to solve a technical issue at the expense of those protections.
“It’s important not to let a technical issue, as it’s presented, undercut market power mitigation,” he said.
While PJM has considered switching to a single schedule, Patel said other options are on the table as well.
PJM Considering Increasing FTR Bid Limit of 15,000 per Entity
PJM presented a problem statement and issue charge exploring the ability to increase the cap on the number of bids a single corporate entity can place in FTR auctions from 15,000 to 20,000 under quick fix rules, with an endorsement sought at next month’s committee meeting.
The RTO is considering the increase following the transition to weekend on-peak and daily off-peak class types, which has had the effect of requiring two bids to trade the same number of hours of an FTR as prior to the transition, according to the problem statement.
PJM senior engineer Emmy Messina said it may be necessary to delay the increase if the RTO finds that existing technology is insufficient to process the higher number of transactions; however, she does believe those upgrades are technically feasible.
“I do believe there are ways we can solve allowing for 20,000 bids if we find that the resources don’t look like they can support it today. Maybe it’s getting upgraded hardware,” she said.
Director of Market Operations Tim Horger said he believes PJM can handle the increase to 20,000 bids in a single auction. However, he cautioned against increasing the number too sharply beyond that.
“I do think we need to be careful with opening the floodgates and going [to] 50,000 [or] 100,000 bids. Let’s do this in baby steps,” he said.
DR Worried by Decline in Synchronized Reserve Prices
Synchronized reserve prices have dropped significantly since the start of October, when new market rules were implemented. Prices were at or below 2 cents/MWh for 95.53% of the hours in October and 97.7% in November, a sharp uptick from previous months. Prices were at those levels 71.81% of the time in September and 36.47% in October 2021. (See FERC Approves PJM Reserve Market Overhaul.)
Synchronized reserve prices have mostly been below the new offer cap of 2 cents/MWh, which was reduced from $7.50 when PJM overhauled its reserve markets, effective Oct. 1. | PJM
“There’s a couple driving factors we believe to be there: One, the offer cap rule going from $7.50 down to the 2 cents, as well as impacts from the must-offer requirement expanding the pool, if you will, of resources that we can procure reserves from,” said Brian Chmielewski, manager of market simulation.
Bruce Campbell, of Campbell Energy Advisors, said that the low prices could push demand response resources out of the synchronized reserve market, which may result in them not being available when the system is tight, even if prices are high.
“There is a concern in the demand response community. … The community is interested in continuing to provide these services, but not interested in providing them for free,” he said.
Chmielewski said PJM is monitoring the price movements and will be providing updated statistics monthly. However, given that market changes are only two months old, it would like to see additional production data before making recommendations for potential changes.
Bowring said the lower prices reflected supply and demand fundamentals and that there is no evidence that eliminating the arbitrary $7.50 adder to offers had any significant impact on clearing prices.
A new study projects that the Inflation Reduction Act will reduce PJM’s carbon emissions while delivering more affordable power.
“Passage of the Inflation Reduction Act this summer threw the full financial weight of the federal government behind the clean energy transition. As a result, CO2 emissions and electricity costs in the nation’s largest electricity market, the PJM Interconnection, will both decline sharply through 2030,” co-author and Princeton Assistant Professor Jesse Jenkins wrote in an email announcement of the study by Princeton’s Zero-carbon Energy Systems Research and Optimization Laboratory. He was joined by Qingyu Xu, Neha Patankar, Mike Lau, and Chuan Zhang in authoring the study.
Using GenX, an open-source optimization and planning model, the study assessed the law’s impact on energy prices, emissions and investments in the PJM grid from 2023 through 2035. The results suggest that carbon-free generation could make up 60% of the PJM supply in 2030, compared to 48% without the passage of the IRA.
With more clean energy coming onto the grid, the study estimated that CO2 emissions could fall 37% over 2019-21 levels, while without the law emissions would be expected to rise approximately 12%.
The study posits that these outcomes are made possible by the tax credits, grants, rebates and loans made available for carbon-free generation, vehicle and building electrification, energy efficiency and carbon capture and storage for natural gas facilities.
“The production tax credit for new carbon-free generation and the production tax credit [PTC] for existing nuclear are the most important provisions in terms of their aggregate impact on the evolution of PJM capacity, emissions and cost,” Jenkins told RTO Insider in an email. “The bulk of new capacity additions are wind and solar leveraging the PTC, and maintaining the substantial existing nuclear fleet across PJM provides a critical foundation for this new carbon-free generation to build on, rather than ‘run to stay in place’ and expend new renewable generation to replace existing carbon-free nuclear generation.”
This could be achieved, the study says, while achieving reductions in the cost of power by lowering wholesale rates, making it cheaper for states to meet their clean energy policy goals through subsidies, and growing electric demand to spread fixed costs.
“This study finds that, due to passage of IRA, the PJM region could cut CO2 emissions from power generation by 80-90% by 2035 while keeping average bulk electricity supply costs for [load serving entities] comparable to or lower than levels experienced in recent years,” the study says.
The study estimates the average 2030 cost for bulk energy for LSEs in the PJM region at $42/MWh — 5% to 10% lower than without the IRA. It notes that costs were $50.20/MWh in 2019 and around $61 in 2021.
The study identified several roadblocks to reaching the projections it made, as well as for maintaining them into the future.
States would have to make their own investments and policy changes to promote the deep decarbonization, for which the study contains a “cost-optimized blueprint.” The roadmap applies two policy constraints to the model to show the impact of a clean energy standard (CES) requiring increasingly carbon-free generation and a CO2 cap-and-trade system.
The CES modeling assumes that 55% of generation will be carbon-free by 2025, 70% by 2030, and 85% by 2035. The cap-and-trade program would have decreasing emissions relative to 2005 levels of 58% by 2025, 80% by 2030 and 95% by 2035.
The expiration of PTCs for nuclear generators could cause the gains made in emission reductions to backslide after 2032.
“Unless equivalent policy support is extended beyond 2032, our modeling finds 12 GW [0-33 GW] of the PJM nuclear fleet is likely to retire by 2035, with new natural gas capacity and generation increasing to fill the resulting gap and meet growing demand, reversing some of the emissions progress achieved through 2030,” the study said.
Independent Market Monitor Jo Bowring said he believes the study includes both optimistic assumptions and outcomes regarding energy demand, prices and the penetration of intermittent resources into the PJM market.
“It’s obviously a very optimistic view of cleaner, faster and cheaper,” he said.
Bowring also noted that the third quarter State of the Market Report calculated the revenue received by nuclear generators over their avoidable costs and found that the resource type is profitable, including under laws such as Illinois’ Climate & Equitable Jobs Act, which he said eliminates the need for additional subsidies to keep the resource competitive.
He also questioned whether the scale of intermittent development is realistic given the low penetration currently seen in PJM and said the study’s LMP estimates for 2025 — which range from the mid $20’s/MWh to the low $50’s — are optimistic given that PJM has been in the $70/MWh range in 2022.
Jenkins said the IRA “fundamentally changes the economics of decarbonization across PJM,” however it will take an acceleration in renewables coming online for the full potential of the law to be seen.
“However, realizing that full potential — including both savings for electricity customers and reductions in CO2 emissions — will require accelerating the rate of renewable energy deployment and, in particular, grid interconnection, relative to recent trends in PJM. That’s a challenge the region as a whole already had a lot of reasons to proactively tackle, and the Inflation Reduction Act gives PJM stakeholders millions (of dollars in savings and avoided emissions) more reasons to do so,” he said.
The Department of Energy’s Loan Programs Office (LPO) announced Monday it is providing a $2.5 billion loan to Ultium Cells, the joint venture of General Motors (NYSE:GM) and Korean battery producer LG Energy Solution, to help finance the construction of new lithium-ion battery manufacturing plants in Michigan, Ohio and Tennessee.
One of the plants, in Warren, Ohio, is already online, producing cells, according to Brooke Waid, a company spokesperson. A plant in Spring Hill, Tennessee, has begun installation of equipment and is expected to be online in late 2023, while construction of a Lansing, Michigan, facility began in September and will continue through 2023. Production there should begin in 2024, Waid said.
The three plants are expected to produce 130 GWh of EV batteries, the equivalent of saving 480 million gallons of gasoline per year, according to the LPO. The projects funded will also create 6,000 construction jobs and another 5,100 jobs in plant operations. The Warren workforce includes 700 members of the United Auto Workers, according to a DOE press release.
“DOE is flooring the accelerator to build the electric vehicle supply chain here at home — and that starts with domestic battery manufacturing led by American workers and the unions that support them,” Energy Secretary Jennifer Granholm said in the release. “This loan will jumpstart the domestic battery cell production needed to reduce our reliance on other countries to meet increased demand.”
EVs now account for more than 5% of all new car sales in the U.S., a key industry benchmark for market growth, according to industry analysts. President Joe Biden wants half of all new car sales to be EVs by 2030. The Infrastructure Investment and Jobs Act includes $7.5 billion to help build out a national network of EV chargers, and the Inflation Reduction Act includes tax credits of up to $7,500 for new EVs and $4,000 for used EVs.
The Ultium batteries use “large format, pouch-type cells,” according to GM. The cells “waste less space and can stack on top of each other like pancakes or vertically like slices of toast. This simple modular design makes it easy for engineers to optimize energy density and vehicle layout,” according to information on the automaker’s website.
In other words, the batteries cost less and can provide more range, according to GM.
The company says it is also working to source as many of its materials as possible from the U.S. as it works toward its goals of producing 1 million EVs per year by 2025 and eliminating all tailpipe emissions from new light-duty vehicles by 2035.
The importance of domestic supply chains and manufacturing jobs was a common theme in reactions to the loan from state and federal government officials.
Michigan Gov. Gretchen Whitmer (D) quickly hailed the loan in a tweet, saying “This will bring supply chains home and ensure Michigan is the best place to innovate, design, and manufacture the future.” The Lansing plant should create 1,700 jobs, Whitmer said.
Quoted in the DOE press release, Sen. Sherrod Brown (D-Ohio) also spoke of the growing competition between states to grab their share of EV manufacturing dollars and jobs. “This loan will support Ohio in taking another step to lead the country and the world in producing sustainable technology and electric vehicles that Americans will need and drive over the next century,” Brown said.
Domestic Supply Chains
The Ultium loan caps a series of administration announcements aimed at expanding the domestic supply chain for batteries, a particular weak point for the industry. Lithium-ion batteries are critical for EV market growth, and China currently controls upwards of 60% of the global market for raw lithium refining and processing.
In October, DOE announced $2.8 billion in grants to 20 companies to supply minerals critical to battery production and bolster domestic manufacture of batteries for electric vehicles and the grid. The companies will use the money to build or expand facilities in 12 states to extract and process battery materials such as lithium and graphite and to manufacture battery components, in some instances, from recycled materials. (See DOE Awards $2.8 Billion to ‘Supercharge’ Battery Production.)
The grants were part of the American Battery Materials Initiative launched by the White House and DOE, to help build out a critical mineral supply chain in the U.S. and in partnership with U.S. allies.
The White House is also hosting an Electrification Summit on Wednesday, where transportation electrification will be a key topic.
