NYISO stakeholders on Friday responded negatively to the ISO’s proposal for a 10-kW minimum capability requirement for individual distributed energy resources to qualify for participation in an aggregation.
Although most proposals discussed at the Installed Capacity Working Group (ICAPWG) meeting did not elicit reactions from stakeholders, NYISO’s 10-kW DER minimum requirement proposal generated significant pushback.
The ISO argued that the proposal would help DER market implementation, save staff time reviewing aggregations for interconnection and enable it to fully integrate new software and internal procedures to comply with FERC Order 2222. (See NYISO Proposes 10-kW Min. Capability Req for DERs in Aggregations)
Stakeholders, however, took exception to the ISO’s language that they would “explore” lowering the minimum capability requirements later after getting experience and a better understanding of DER penetration versus directly promising to lower the minimum capability later.
Chris Hall, of the New York State Energy Research and Development. Authority, summarized the main concern, arguing that, with average size of residential storage resources at 7 kW, the “provision essentially eliminates all of these residential assets from participating.” Though NYSERDA is “sympathetic to the ISO’s limitations,” it is “deeply troubled by this proposal,” he said.
Adam Evans of the New York Department of State agreed with Hall’s assessment, stating that “folks at the DPS who are close to these types of resources have been hearing that this proposal would pretty much eliminate residential participation.” NYISO’s intention should be to “get more resources to participate” and that putting “a barrier right from the get-go” was inadvisable, he said.
David Skillman of Sunnova Energy echoed these complaints, saying how his company’s fleet consists of resources between 6 and 8 kW, meaning they would not be able to participate in aggregation. That, he said, “flies in the face of FERC 2222,” which was established to “give the small guys a chance to play on the same field as the big guys.”
Aaron Breidenbaugh of CPower shared how recent conversations he had at the Advanced Energy Management Alliance indicated that there was “pretty significant concern about the potential disenfranchisement of an entire customer class” and suggested that NYISO change the language of “explore.”
Other tariff revisions or modifications were collectively proposed to clarify existing rules and processes.
These included making no aggregation types eligible for the NYISO Station Power program, accommodating retail charging rates for aggregations and clarifying several rules in the ISO’s Market Administration and Control Area Services tariff.
The ISO intends to return to an upcoming ICAPWG meeting to further review the draft language and then expects to seek approval from Business Issues Committee and Management Committee later this year. It would then file the proposals with FERC for an anticipated implementation in 2023.
Also during Friday’s ICAPWG meeting, NYISO Principal Economist Nicole Bouchez presented the results of a study examining the differences in expected ramp-up and ramp-down rates as the grid undergoes rapid transition, the impact of seasonality impacts and the rate of growth as more intermittent resources are added.
The ISO examined two policy cases listed in the outlook for the years 2030 and 2040, calculating their ramp rates, average number of ramp hours per event and hourly percentiles to better show distribution of the rates.
Bouchez pointed out that initial findings “qualified as having no real observable trend” in the number of hours ramped over time, and that if anything, one could “posit that ramp-down events are a little bit longer, but even that is difficult to say.”
However, when NYISO examined how many megawatts there are in those ramp periods, it found that the ramp rates were “amplified” in magnitude over time as “more and more installed capacity of renewable resources” were added.
More important, Bouchez said, the ISO found that although ramp events are normally distributed over time, the average ramp megawatt is impacted across the seasons.
For Case 1 there were less ramp up and down needs in the shoulder seasons. Case 2 had more ramp needs in the winter, while both the summer and shoulders were similar.
Bouchez stated that the findings will be included in a white paper that the ISO expects to present in draft form either in late October or early November, after which there will be a stakeholder comment period of three to four weeks. She also said that any related market changes or additions will be studied in next year’s Balancing Intermittency Project, which will use the data presented at Friday’s meeting for structure.
Transmission owners found themselves on the defensive throughout Thursday’s FERC technical conference on transmission planning and cost management, as panelists decried the rising spending on end-of-life and other local projects that do not face any prudency reviews.
Kamran Ali, vice president of transmission planning and analysis at American Electric Power (NYSE:AEP), pushed back against the criticism, saying PJM’s Attachment M-3 process, which governs planning of supplemental projects — those not needed for system reliability or public policy compliance — is “the gold standard” for transparency.
Lisa McAlister, American Municipal Power | FERC
“I can say that because I manage the transmission planning for AEP in four different RTOs,” Ali said. “I think it would be beneficial if people were to bring actual factual examples to the table: ‘In the M-3 process, here are the regional projects that would have displaced local projects, or here are the local investments that were not prudent, that were not rationalized that somehow made it through.’ If we have some of those real examples, I think we can enhance the M-3 process. Without examples I think it’s very difficult to make any improvements.”
PJM evaluates supplemental projects only to make sure they do not harm reliability. Municipal stakeholders have long complained about the lack of transparency surrounding their costs. (See PJM TOs Sign off on Supplemental Project Deal.)
Lisa McAlister, general counsel for regulatory affairs for American Municipal Power, responded that the reason that there are no examples is “because we simply don’t have enough information to identify” any. She said AEP does “a better job” than other PJM TOs in providing information, but “what we don’t have is how those replacements are prioritized; we don’t know [how] replacement versus maintenance decisions [are made]; how assets rank compared to other assets on the system.”
‘Appearance of Transparency’
“AEP has done a very good job in the M-3 process of responding to a limited number of suggestions,” agreed Kentucky Public Service Commission Chair Kent Chandler. “I have a certain number of questions, and [there] are now stock answers that they’re ready to provide people. … The reality is that although I understand what their criteria is … I have no idea what weight they’re giving” to them.
Kentucky Public Service Commission Chair Kent Chandler | FERC
“The M-3 process gives us far more insight into local planning than the non-RTO utilities that we have, and even the MISO utility that we have,” Chandler added. “We understand through the M-3 process what their assumptions are and the criteria maybe, but there’s no way that we’re provided enough information to be able to replicate the decisions that are made by the utilities. So we understand that they may be looking at asset conditions, [but] we have no idea what kind of weight they’re giving them; whether they’re prioritizing certain conditions over others. It’s the appearance of transparency, and it’s enough to maybe placate some folks … but it is not enough to have an appreciation for how they’re actually doing local planning.”
But that’s still far more than what the PSC gets from its non-RTO utilities, he said. “We don’t find out what their planning outputs are until they show up to the commission for a certificate of public convenience and necessity, or it’s a fairly small transmission project and we don’t see until they file a rate case and it shows up in their forecasted test period. … We have no insight into their local planning.”
McAlister said RTOs should do more rigorous analyses of local planning criteria and proposed projects. But “to really have a meaningful opportunity to have a back-and-forth, you need more than the ability to submit comments,” she said. “There has to be some kind of actual requirement that the transmission owners respond.”
Greg Poulos, Consumer Advocates of PJM States (CAPS) | FERC
She said PJM created a website for members to submit questions, but the RTO usually just says, “we’re working with the transmission owners; we’ll get back to you.” She said mirroring the M-3 process in other regions, “just having an arbitrary set of meetings and days to comment, we don’t think is something that gets us there.”
Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said in-house experts can only do so much.
“We have the money to hire an expert. I just don’t know what our expert would do with only 10 days to review projects, no ability to ask the questions and no expectation that they’re going to respond to us,” he said.
“Those are things you would hear from … an independent transmission monitor: ‘Those are flaws in this process. There’s a significant gap here [and] PJM, you need to do something about that.’ It’s different from me saying that, because I’m not getting response to that.”
Kenneth Seiler, PJM’s vice president of planning, said the RTO has not pursued more regional projects because the RTO is not seeing high load growth except in some areas such as Northern Virginia, which has experienced an explosion of data center load. (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)
Kenneth Seiler, PJM | FERC
“We look for opportunities for regional transmission, but in many cases, it’s not the most cost-effective solution,” Seiler said. “We have had occasions in the past, though, where we had identified regional solutions [and] we could not get the line sited. The one example I can think of off the top of my head was about a $100 million regional transmission facility … The [state] commission wouldn’t site it within that particular state. And we ended up spending over double — over $200 million for sub-transmission upgrades.”
Erik Heinle, of the D.C. Office of the People’s Counsel, said PJM’s expertise in engineering and power flow analysis is “world class.”
“But we see far too many instances where PJM is not acting as the regional planner and bringing regional projects to the region,” he said.
Existing Cost Containment Practices
FERC Commissioner Willie Phillips expressed interest in MISO’s variance analysis, in which the RTO reevaluates projects facing lengthy schedule overruns or a 25% cost increase. MISO can either let projects continue, cancel them or assign them to different developers. Jeanna Furnish, MISO’s director of expansion planning, said the variance analysis could be applied in other regions to scrutinize projects.
FERC Commissioner Willie Phillips | FERC
SPP Executive Vice President of Regulatory Policy Paul Suskie said that, more than a decade ago, SPP’s first regionally funded 345-kV line turned out to be significantly more expensive than its original estimate, causing the RTO’s Regional State Committee to call for a review and develop methods to contain costs. Since then, Suskie said, SPP has been tracking project costs in an evolving process. He said projects that exceed 20% of their original costs are subject to restudy, suspension and even cancellation.
FERC Chair Richard Glick asked transmission owners how they currently reduce cost exposure for customers on large, regional transmission projects.
Carolyn Cowan Barbash, vice president of transmission development and policy for NV Energy, said her company tries to write projects’ technical specifications as clearly as possible and makes sure it attracts multiple bidders on solicitations.
Ameren Transmission Company (NYSE:AEE) President Shawn Schukar said his utility considers how large projects will impact future projects and vets contractors for past performance in addition to their cost estimates. He also said Ameren considers the quality of transmission components and how often they might need maintenance and replacement. He said he “took exception” to the perception that transmission owners aren’t currently motivated to keep costs in check.
‘Cooking the Books’
Attorney Lauren Azar, a former Wisconsin regulator, said FERC should create a process for challenging local planning criteria (LPC), saying “a few bad apples” in MISO have overly restrictive criteria for the generation interconnection process.
“Even before any new generation is added into the models, upgrades are already required, because of the LPCs. So in other words, the TOs are cooking the books so that those generators are required to pay for those upgrades, even before their proposed generation is added,” she said. “That’s not OK.”
Grid-enhancing Technologies
Panelists also weighed in on the role of grid-enhancing technologies as a way to cut costs.
PJM’s Seiler said the industry could benefit from a guide identifying where grid-enhancing technologies “would have the biggest bang for the buck.”
Erik Heinle, D.C. Office of the People’s Counsel | FERC
“There’s a lot of reluctance on behalf of our asset-owning utilities to apply grid-enhancing technologies, frankly, because of things like the reliability of the internet, security of [the technologies and creating an] additional avenue by which we could be attacked from a cybersecurity view.
“And these things have to be reliable. From a pure planning viewpoint, in my mind, there’s very few grid-enhancing technologies that can be relied upon on a day-in, day-out basis where I know I can count on having that extra transmission capability.
“Things like dynamic line ratings can be applied on the physical transmission line to squeeze out a few more megawatts from a pure system operations view. From a planning view, I can’t count on” them, he said.
Heinle disagreed, saying GETs should be part of regional planning. Distributed energy resources “served as a valuable planning tool in California a few weeks ago. And when you hear comments like, ‘Well, we can’t always count on this or that’ — those were similar comments that we heard about solar [and] wind, not too long ago. We found ways to incorporate them into the grid, and to use them in our planning for resource adequacy.”
Glick asked consumer advocates if grid planners give sufficient consideration to alternatives when local transmission projects are proposed.
CAPS’ Poulos said there is not: “The transmission owners in the [PJM] region say, ‘We have control of whether we’re going to do grid-enhancing technology. You have no input on this.’”
Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR
VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a PJMeffort to prohibit critical gas infrastructure from participating in demand response programs that could jeopardize the reliability of gas-fired generators. The endorsed language revises sections of manuals 11 and 18 to add language excluding “critical gas infrastructure” from being eligible as price responsive demand programs.
The changes are being considered as NERC and FERC work on their own efforts to address concerns raised by the impact of February 2021’s winter storm — that a spike in load could lead to gas infrastructure being curtailed and causing a cascading failure as downstream gas generators have their fuel interrupted. The PJM language would stand until the federal regulatory bodies finalize their own standards. (See “Critical Gas Infrastructure Approved,” PJM MIC Briefs: March 9, 2022.)
Much of the lengthy discussion on the topic focused on how PJM is considering defining critical gas infrastructure in its tariff: “as electric loads, which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation.” The tariff language is not part of the package endorsed Thursday and is still being fine-tuned by PJM staff with input from Thursday’s meeting.
At issue was the definition of “significant impact.” Calpine’s David “Scarp” Scarpignato questioned how PJM would classify a curtailment causing a drop in pipeline pressure causing a downstream gas plant to run at less than full capacity, or a curtailment that doesn’t cause a direct drop in a plant’s ability to generate but has that effect when combined with other contingencies.
“A significant impact is a difficult measure. That’s going to be difficult to implement those rules. … I wonder if we can substitute ‘direct’ for ‘significant,’” he said.
Joe Bowring, PJM’s independent market monitor, said he believes the language is “fuzzy” and therefore not enforceable. He also questioned whether there’s a risk of gas infrastructure being enrolled in DR programs this winter (2022/23) as PJM considers the revisions, which will not be applied until the winter of 2023/24. Bowring also questioned why PJM has not done its own assessment of the facilities rather than relying on the sellers of demand response for the information.
PJM’s Peter Langbein said curtailment service providers have told staff that there are not currently any gas infrastructure facilities enrolled in their programs that would meet the general definition under consideration.
Paul Sotkiewicz, of E-Cubed Policy Associates representing J Power USA, said he’d prefer to see an explicit prohibition against electric-driven gas compression stations participating in DR in any form.
“We’re setting ourselves up for a cascading failure without addressing compression,” he said.
Elimination of ‘CT Rule’ Receives Endorsement
Stakeholders also endorsed manual revisions being sought by PJM to eliminate the “CT Rule,” which grants combustion turbines an exception from rules requiring that generators follow dispatch signals. Currently CTs can recover the costs of their full generation regardless of their load signal, while other generators receive the lesser of their actual generator or their dispatch.
PJM’s Lisa Morelli, director of market settlements initiatives, said the rule is a holdover from when CTs put out a fairly constant rate of power. Now that they have a wider dispatchable range, it makes sense to require them to conform to dispatch, she said. The elimination of the exception can be made by removing a single line in Manual 28.
“CTs will now be treated as all other resources in balancing of operating reserve credits,” she said.
During the Sept. 21 Markets and Reliability Committee meeting, Morelli said simulations show that uplift payments to CTs were about $1.3 million lower when recalculated without the exception over the eight highest CT uplift days in summer 2021, a 10% drop. (See: “PJM Staff Seek Removal of CT Exception on Load Signaling,” PJM MRC/MC Briefs: Sept. 21, 2022.)
Impact of State and Local Regulations on Net CONE Discussed
PJM staff provided a first read on an issue charge and problem statement exploring how local considerations, such as state and local regulations, might affect the development of the net cost of new entry (CONE). The topic will return to the MIC for possible endorsement at its next meeting.
James Wilson, a consultant to state consumer advocates, recommended broadening the issue charge and potential solutions to include other possible changes beyond net CONE, such as to the shape of the variable resource requirement curve.
Gary Helm of PJM said the RTO’s intent was to stick with addressing CONE and net CONE, as opposed to weighing the outcomes.
Four-year Review of Default CONE and ACR Underway
PJM’s Skyler Marzewski and consultants from The Brattle Group presented an overview of the first four-year review of the default CONE and avoidable cost rates and the timeline for drafting the new values.
PJM’s tariff requires the RTO to update default gross CONE and default gross ACR values for minimum offer price rule purposes every four delivery years beginning with 2022/23.
The methodology would use public national sources for the installed capital costs and fixed operating and maintenance costs, as well as using the same financial assumptions as in the quadrennial review.
“It will be a very similar process to what we did last time,” Marzewski said.
Stakeholders questioned if there’s sufficient geographic variability to justify using data specific to the PJM region, instead of national data. Marzewski said this was explored; however, it was found that there’s limited local data available. The largest variations in the cost of development tend to be the size and configuration of generators, according to Brattle’s presentation.
Default values for offshore wind were not explored in the analysis thus far as the focus was on existing generation. Instead, unit-specific analysis would be undertaken for OSW, as well as other generators with highly variable costs.
PJM Reviews Proposed VOM Language
PJM staff reviewed a set of proposed manual revisions that would codify a PJM package creating standardized variable operating and maintenance costs. The RTO’s package was the preferred solution coming out of the MIC’s Sept. 7 meeting, receiving more than 70% support over a competing package from Constellation Energy, which received 54%. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Constellation’s Jason Barker questioned PJM’s classification of nuclear major maintenance costs as variable costs that are directly related to electric production based on starts and run hours and thus must be reflected in a unit cost-based offer, rather than in a capacity market offer. Barker said there is an apparent contradiction in PJM’s proposed Operating Agreement and manual provisions that define nuclear refueling and other major maintenance projects as “variable” while also excluding time-based or preventative maintenance from classification as a variable cost. Barker said that Constellation and other nuclear operators consider costs incurred during planned nuclear outages as “fixed” costs. He also highlighted that all nuclear planned outages are scheduled years in advances, suggesting that projects undertaken during those outages are time-based. The company’s package would exclude nuclear planned outage costs from PJM’s definition of major maintenance.
The manual changes will go to the MRC on Oct. 24 for a first read with a vote anticipated on Nov. 16.
Other MIC Topics
A first read was presented on a proposal to merge the DER & Inverter-Based Resources Subcommittee and Demand Response Subcommittee into a new subcommittee, given the similarity of the subjects they cover and the composition of their stakeholder participation. PJM staff said doing so would simplify scheduling internally and for stakeholders, although there were some concerns that doing so could conflate their charges and the issues they aim to address.
PJM’s Andrew Levitt gave a first read of a proposal to expand the RTO’s current hybrid resource provisions to include installations with multiple types of generation paired with storage. The current hybrid definition allows for only one type of generation, for example solar paired with storage, while the Hybrid Resources Phase II solution would allow for “any number of different types of [generation].” The proposal would also create a detailed energy market model for inverter-based resources paired with storage, such as wind and solar combinations.
PJM provided an explanation on the impact of negative day-ahead and real-time LMPs in the calculation of the balancing operating reserve credits. Negative DA or RT LMPs can result in unnecessary BOR credits caused by the treatment of day-ahead or balancing revenues, the RTO says. PJM plans to present potential solutions during future special sessions.
FERC Commissioner Mark Christie said Thursday that the commission should consider limiting formula rate authority to transmission owners whose projects are subject to “robust” state regulatory reviews to help close the “regulatory gaps” between state, federal and RTO oversight.
Meanwhile, state officials and consumer advocates told FERC’s technical conference on transmission planning and cost controls (AD22-8) that the commission should also provide more scrutiny of formula rates, under which expenses are presumed to be just and reasonable.
Christie was incredulous when Indiana regulator Sarah Freeman, president of the Organization of MISO States, said that her state has no process for reviewing transmission projects.
“There is a gap in what scrutiny is taking place at the state level, and yet that is where all these projects should be scrutinized,” Christie, a former Virginia regulator, said at the close of the hearing. He said the testimony showed state oversight on the cost and prudence of projects “varies greatly.”
FERC has “authority over [just and reasonable] rates at the wholesale level and transmission. We don’t have authority to tell a state how to structure your CPCN [certificate of public convenience and necessity] process, but we do have authority to say who gets formula rate treatment when you come here,” Christie said. He invited stakeholders to submit comments on whether FERC should limit such rate treatment to TOs from states with a “robust state permitting process.”
“At a minimum, a robust state permitting process would be looking at, not just [the] prudence of cost, but also looking at need,” Christie said. “If you look at the three sections we’ve talked about today — the RTO planning part; the state CPCN part; and then the formula rate part [at FERC] when it comes to how to pay the bill — each one of those really connect.”
FERC Chair Richard Glick said he was taken aback by Iowa Consumer Advocate Jennifer Easler’s written testimony, which described the state’s lack of authority over the cost of local transmission projects.
“When they come in for the franchise application, we do conduct discovery on it, and we ask, ‘What alternatives did you consider?’” Easler said. “And we will get responses along the lines of, ‘We object. The costs of these projects are not regulated by the Iowa Utilities Board.’”
Glick said the conference exposed both a regulatory gap and “an informational gap,” as evidenced by regulators and consumer advocates who said they lack the access to information on local transmission plans or the expertise to evaluate them. “Those are two items I think we need to address going forward,” he said in his remarks concluding the conference. “We have, in my opinion, more work to do on transmission and hopefully more [Notices of Proposed Rulemakings] to come at some point.”
States Seek Help
FERC heard from officials of eight states and D.C. during the daylong conference.
Cameron Dyer, senior assistant general counsel for the Public Utilities Commission of Nevada, said there is only one vertically integrated investor-owned utility in his state — NV Energy — that “handles just about all the transmission in the state, which means that any time new transmission is being proposed — in the intrastate context, at least — there is a lot of robust interview, review and analysis of that new transmission.”
Most state officials were less sanguine.
The topic of the first of the five panels at the conference was the development and use of criteria for local transmission planning, where state regulators and municipal utilities told the commissioners they often don’t have any idea what those criteria are.
Under FERC Order 890, “we get the baseline reliability criteria from the transmission providers and [their] specific engineering criteria for their projects, and that’s all,” said Dan O’Hagan, manager of regulatory compliance for Florida Municipal Power Agency. “We don’t get other criteria that go into that decision-making process, like end-of-life for facilities, or cost considerations, or public policy considerations … that might come into play behind the scenes where they select one project over another.”
Simon Hurd, program and project supervisor with the California Public Utilities Commission, said the PUC appreciates its working relationship with Southern California Edison and Pacific Gas and Electric, but the discussions are mostly past-tense because 63% of utility projects are self-approved. These projects are not put into the transmission planning process and they do not get CAISO review, he said.
“We need to be more upstream. … We want review; we want input in the process at the assumptions, the needs, the solution stage. We’re doing our best to be having that conversation with the utilities, but it’s after the solutions have already been identified,” Hurd said.
Too Late
James McLawhorn, director of the North Carolina Utilities Commission’s Energy Division, said the NCUC enters the process too late.
“We have attempted to question some of the projects that have been proposed as to whether there are other options. … By the time it comes to us, we’re being told, ‘Well, no, this is the only solution that was available and now we’re out of time and we need to move forward with it,’” he said. “Maybe it was the only solution that was available, but we simply don’t have the information to evaluate that.”
McLawhorn, who advocates for consumers as part of his job, was among speakers who favored an independent transmission monitor to increase oversight of the transmission planning process.
“The commission looks for us to do the evaluation, to come to them and make recommendations, but we do not have particular transmission expertise on staff, and we desperately need something like an independent transmission monitor to assist us,” McLawhorn said. (See related story, States Urge More Transparency on Tx Planning, Independent Monitors.)
The North Carolina commission recently engaged a transmission consultant to provide that help, McLawhorn said, but the process was a struggle. There was one response to the request for proposals, he said, and it came in on the last day of the submission period.
Phil Bartlett, chair of the Maine Public Service Commission, said that by the time his agency gets to review a transmission project, it “is pretty far along.”
“So even a very robust process, in my view, is not a substitute for really engaging early on the planning process. It’s also not a substitute for following through afterwards.”
In contrast with FERC’s lack of scrutiny for prudency, Bartlett said, “we are always looking at the prudency of investments that have been made. And that includes the management of those projects in development. We routinely disallow costs if we think there are unreasonable overruns or other issues. So, both in terms of not being present at the planning stage, and not being present after the CPCN process on the cost-management side, I think it’s a real shortcoming of even the most robust CPCN process.”
Formula Rates
Bartlett and others said the use of formula rates has shifted the burden of proof. In state rate cases, TOs must demonstrate just and reasonable rates; under formula rates, states and consumer advocates must rebut the proposed rate.
Ron Gerwatowski, chair of the Rhode Island Public Utilities Commission, said his commission recently discovered that Narragansett Electric (now Rhode Island Energy) was collecting $10 million a year in excess profits on its transmission line connecting the Block Island offshore wind farm to the mainland.
“It is telling to consider that the windfall profit being generated from the formulaic cost-recovery mechanism used in this case was only discovered because someone in the accounting department of the utility misallocated revenue and expenses to the wrong business unit in a report on distribution earnings,” he said in his written testimony. “But for that human error, neither the Rhode Island PUC nor FERC’s processes would have picked up the continuing windfall profits flowing from ratepayers to shareholders.”
Gerwatowski said that more than $2.5 billion in “asset condition” projects have been placed in service in New England and $3.1 billion more are listed in ISO-NE’s Regional System Plan (RSP) as proposed, planned or under construction. By comparison, as of the June 2022 RSP update, reliability projects in the pipeline resulting from the ISO-NE planning process total less than $1.3 billion.
Attorney Robert Weishaar, who represents industrial consumers, said FERC’s Office of Administrative Litigation (OAL) could play a larger role in the transmission formula rate review process.
He said OAL staff are “extremely helpful” in the initial establishment of formula rates but become uninvolved when it comes time for annual updates. Weishaar suggested that FERC expand OAL’s authority and resources so staff can engage in the annual update process and “review the actual flow-through of the costs.”
Larry Gasteiger, executive director of WIRES, saw it differently. He said formula rate protocols involve “extensive” stakeholder sessions with utilities and opportunities to challenge the rate inputs.
In addition, he said, FERC has “a fairly robust” program for auditing utilities with formula rates. “The audits, I know from personal experience, are extensive,” said Gasteiger, who served at FERC for almost two decades, including almost six years as a top official in the Office of Enforcement. “And they are effective, because they do a very thorough examination of how adherence to the rate protocols and the formulas is all working.
“If you believe the rhetoric around it, FERC has all but abandoned any regulation of transmission rates in this context,” he continued. “I think it’s important to debunk that notion. Maybe it plays well in the Twitter-space, but it doesn’t reflect the reality of what is going on here.”
But FERC Commissioner Allison Clements noted that the commission only conducts about a dozen audits a year. Although the Office of Energy Market Regulation has “improved stakeholders’ ability to engage on formula rates,” the “structural problem” with formula rates may require appointing independent transmission monitors, she said.
“The cost is peanuts on the dollar of deferring just one transmission investment,” she said. “But if that’s not the way you think we get at these problems, we certainly are open to other ideas. … I think I hear a real need to take action.”
In addition to increasing its scrutiny of formula rates, Bartlett said FERC should revisit the return on equity allowed for formula rate investments. “Given the lack of oversight and difficulty in challenging prudence, there is little risk in undertaking these investments and the ROE should reflect that,” he said.
Iowa Consumer Advocate Easler was also critical.
“Transmission providers that use forward-looking formula rates with incentive ROE adders and obtain automatic cost recovery of transmission costs from retail customers via state-authorized transmission cost trackers simply do not have a strong incentive to engage in least-cost transmission planning for lower-voltage local transmission facilities,” she said in her written testimony. “The absence of customer-initiated challenges to local transmission upgrades in formula rate reviews is not an indication that all is well. Rather, in the face of relentless transmission rate increase, it is an indication that this regulatory process is inadequate to protect customers from unjust and unreasonable charges resulting from inefficient siloed transmission planning processes.”
The Operating Committee endorsed a revised package of changes addressing renewable dispatch after the proposal had been sent back to the subcommittee level for additional fine tuning last month. The joint Independent Market Monitor/PJM proposal would require intermittent resources with capacity commitments to offer economic maximum megawatts equal to or greater than their hourly forecast.
Stakeholders speaking at the Sept. 8 OC meeting worried that the original language could result in renewable output being held back by use of an under-forecasted value and opted to send the proposal back to the DER and Inverter-Based Resources Subcommittee rather than vote on it. (See “Renewable Dispatch Proposal Vote Delayed,” PJM Operating Committee Briefs: Sept. 8, 2022.)
Some stakeholders were concerned about the proposal’s elimination of the curtailment flag, which PJM uses to notify generation operators that their units have been curtailed and that they should adjust their output accordingly. Friday’s presentation said the intent is to have generators following economic base points, rather than curtailments, which can be inadvertently prompted because of bid-in parameters or offers.
“I think we were able to work through those concerns,” PJM’s Michael Zhang said.
Cold Weather Preparations Begin
PJM is beginning to implement annual cold weather preparations, with data reporting for generating unit reactive capability verification underway from Oct. 1-31 and reporting for the seasonal fuel inventory and emissions data request beginning Oct. 17 and remaining open through Nov. 21. The cold weather preparation guideline and checklist will also be open Nov. 1 through Dec. 15.
The RTO is no longer facilitating a formal cold weather exercise and is asking generators to self-schedule their own testing in December on a day when temperatures are forecast to be below 35 degrees F.
Fuel Inventories Remain Low, Expected to Increase Going into Winter
Fuel production rates are up across most resource types, but inventory stocks remain low as volatility and prices remain high, according to the fuel supply overview presented to the OC. (See NERC Warns of Fuel Shortages Going into Winter.)
Oil inventories remain below their 5-year average as economic concerns continue to outweigh high production. | PJM
Distillate and residual fuel inventories remain about 9% below their five-year averages on the East Coast, PJM Principal Fuel Supply Strategist Brian Fitzpatrick said, while recession fears and a strong dollar continue to keep prices high.
Progress on contract negotiations for rail workers has alleviated concerns about a strike; however, not all unions have signed onto the agreement, and it’s believed that the process could continue through the Nov. 20 ratification deadline.
Production of both oil and coal fuels remain above average, and Fitzpatrick said inventories are expected to rise over the coming months as generators stock up for the winter season.
“So far, based on the response we’ve seen, no significant concerns have arisen,” Fitzpatrick said. “There have been signs of improvement recently with inventory build.”
Revisions to Fuel Requirements for Black Start Resources Presented
PJM’s Thomas Hauske went over the clarifications and revisions made to the proposed solution addressing fuel requirements for black start resources, which was endorsed by the Operating and Market Implementation committees last month. The Markets and Reliability Committee is scheduled to vote on the revised proposal during its Oct. 24 meeting. (See PJM, Monitor Debate Black Start Fuel Requirements Proposals.)
A provision allowing intermittent generators to contribute black start capacity as long as they are capable of providing 16 hours of full load operation with 90% confidence was clarified to ensure that it is only applicable for renewables. PJM also clarified that if a unit has its installed capacity increased because of a capital recovery upgrade, its black start revenues will be reduced commensurate with the increased capacity revenues received from the upgrade — preventing the generator from being paid twice for that added capacity.
Generators that store fuel onsite and are connected to two or more interstate pipelines will not be penalized if their fuel inventory falls below the 16-hour supply requirement if they can instead operate on fuel from the pipelines in the event of a black start.
Other OC Discussions
The OC reviewed the recommended winter weekly reserve target from the 2022 reserve requirement, with a vote expected at the next meeting. This year’s recommendations are largely lower than last year’s study results, with 21% for December, 27% for January and 23% for February.
The implementation of PPL’s dynamic line rating initiative is now live, after being delayed from the anticipated go-live date on Sept. 28. The program is now active following an Oct. 6 launch. PPL had already delayed an expected July launch until September because of additional work needed for changes to its energy management system by its vendor. (See “PPL Delays DLR Implementation to September,” PJM Operating Committee Briefs: July 14, 2022.)
ATLANTIC CITY, N.J. — Spurred by the rapid rise in renewable energy project planning and declining battery costs, storage development is growing nationwide, but states need to ensure that they fund, shape and incentivize projects that contribute to their emission-reduction goals, a speaker told New Jersey’s Clean Energy Conference on Oct. 4.
States such as New Jersey, which is in the process of planning its first large-scale electricity storage incentive program, need to focus not only on stimulating storage capacity development but on making sure that the resulting projects help cut the use of fossil fuel generating plans, Todd Olinsky-Paul, of the Clean Energy States Alliance, said on a panel at the conference, organized by the New Jersey Board of Public Utilities (BPU).
The goal is “not just to get the storage there; it’s to get it there and link it to whatever policy targets or aspirations the state has,” Olinsky-Paul said. Projects need to charge up their batteries with cheaper, off-peak power and be ready and available to discharge when demand is greatest, to help negate the need for utilities to fire up fossil-fueled peaker plants, he said.
His comments came amid what he said is a dramatic increase in storage development in almost all states. Ten years ago, he said, he could have summed up national storage development activity by citing a handful of programs. “But things have exploded so much in policy in the last few years that I can no longer do that,” he said.
The rapid advance of the sector prompted another panelist, Brian Kauffman of Enel North America, to advise states looking to jumpstart or boost their storage capacity that they no longer need to think of developing a pilot program first.
“There’s a lot of examples of how to structure them and what results in customer uptake. There’s a very mature ecosystem of competitive purchase market participants,” Kauffman said.
“A lot of times, these pilot programs are set up where you don’t really know what the cost of doing the project is going to be [or] who’s going to participate in the project; you just want to learn,” he said. But now, “you have thousands of customers who are participating in programs across a dozen states or so.”
Finding the Right Incentive Level
Storage is widely seen as a paramount element needed to manage electricity supply as intermittent renewables become increasingly dominant.
The conference came just after New Jersey, admitting that it had lagged state ambitions in developing storage capacity, released a straw proposal on Sept. 27 that outlined a plan to stimulate the development of standalone storage capacity by offering incentives for grid-scale and consumer-level projects. (See NJ Offers Plan to Boost Lagging Storage Capacity.)
The BPU’s plan, known as the Storage Incentive Program (SIP), would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.
Jim Ferris, deputy director division of clean energy at the BPU, told the conference that the fixed incentives would be awarded using a “declining block structure” that has worked in other states. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower rate.
“In that way we are providing certainty to the market, but also finding the right incentive level,” Ferris said. “Obviously, if a particular block does not fill at that incentive level, we will have the opportunity to either extend that particular block and incentive or even go back and increase the incentive.”
The agency also has sought to ensure that it does not provide financial support for a project that “just sits unused,” he said. To receive the incentive, “the device will need to be available for 95% of hours,” he said.
The pay-for-performance incentive, which is based on PJM marginal carbon intensity data, is designed to tie the BPU’s incentive to demonstrable emissions reductions, Ferris said.
“So we would be incentivizing when storage is charged when emissions are low, and discharged when emissions are high. And that delta will yield an incentive,” he said. The performance incentive for distributed projects is based when the project injects energy into the system or is used to reduce the use of energy at the request of electric distribution companies, a strategy used in programs in Connecticut and Massachusetts, he said.
Monetizing Storage
States have taken different approaches in seeking to stimulate storage development, CESA’s Olinsky-Paul said. They include mandating a certain amount of storage by a particular date, or just setting a target capacity procurement, he said. Nine states have set a target. Among them are California, shooting for 1,825 MW by 2020; Massachusetts, with 1,000 MWh by 2025; New York, with 3,000 MW by 2030; and Oregon, 5 MWh by 2020.
He displayed a slide that showed more than two dozen states have taken three or more types of action to plan for storage development, including studies and investigations, new policies and regulations, and financial incentives and rates. And all but three states have taken at least one step toward storage development.
One difficulty in stimulating storage development, according to the BPU and panelists at the conference, is that storage devices are difficult to “monetize,” which in turn puts the onus on state support. For that reason, the BPU proposal encourages investors in storage projects to pursue “value stacking,” or looking for several revenue streams to support the project.
While storage projects can provide benefits such as reduced electricity costs and emissions, “the current revenue streams, as in a lot of places in the U.S., including New Jersey, really aren’t sufficient now for storage to scale,” Enel’s Kauffman said.
Olinsky-Paul said one of the “best practices” that states should follow is identifying the attributes of a project that are “priced” or monetizable. He cited the example of a service station owner who installs a storage project on the property.
“So when the grid goes down, I’m able to fuel customers’ cars, first responder vehicles; that’s providing value to the community,” he said. “Did I get paid for it? No. Because there is no market for resilience. I can’t bid that service into a market or sell that service to utility as a backup power service.”
So the state needs to look at the balance of monetizable and non-monetizable benefits and work out “how are we going to provide that gap funding somehow to encourage that market to develop,” he said.
For the operator, the monetary benefits depends on the business model that the storage operators develops, Olinsky-Paul said. For example, the operator may use an arbitrage model of charging up the storage at night when the power price is low and selling the energy at peak hours when the price is higher, he said.
The operator of a solar farm may find storage provides “capacity value,” which in turn provides a financial revenue, he said.
“Solar by itself doesn’t have a lot of capacity value, because it doesn’t have an on-off switch; you can’t rely on it,” he said. “So you’ve now firmed the solar power that was previously variable. Well, there’s a value to that. If you’re bidding that power into a wholesale market, and they want firm power, they’re going to pay more for it if they know that you can turn it on and off than if you are just at the mercy of the clouds.”
Rensselaer, N.Y. — NYISO is proposing to broaden its rules for including projects in the base cases of transmission studies because of an increasing risk that projects studied in one process may affect those studied in others, the ISO’s Thinh Nguyen told the Transmission Planning Advisory Subcommittee Oct. 3.
Because of timing issues, projects being studied in the ISO’s transmission interconnection procedures (TIP) do not always meet the base case inclusion rules of the class year study, or vice versa. As a result, Nguyen said, there may be interactions among these projects that need to be studied.
Nguyen also said the chance of this issue between studies being conducted in parallel has increased with the rise in requests entering the NYISO interconnection queue as well as the increasing number of distribution-level projects.
One proposed enhancement to the ISO’s rules would revise the ISO’s base case inclusion rules to specifically refer to projects being studied outside of the ISO’s procedures that a transmission owner identifies as having advanced sufficiently to be considered “firm” in the TO’s planning its local system.
Another change would add tariff provisions on the use of sensitivities and true-up studies in the TIP facilities studies to account for interactions with class year projects that could require the same or similar upgrade facilities. Following the completion of a class year study, the ISO will conduct a true-up to reflect class year projects accepting or rejecting their cost allocations and posting security to continue development.
Although the current tariff allows the ISO “flexibility” to account for these timing issues, the ISO said explicit tariff provisions detailing the use of sensitivities would improve coordination between the study processes.
The ISO plans to present proposed tariff revisions later this month or early in November.
RNA Draft Report Findings
The ISO presented findings from its fourth draft of the 2022 Reliability Needs Assessment (RNA), which did not identify any reliability needs for the 10-year study period but found that resource adequacy and transmission security margins are tightening over time.
The RNA report identified the risk that extreme weather events, such as heat waves and severe storms, could result in significant reliability deficiencies reducing the ability to serve demand, particularly in New York City.
The RNA also evaluated the impact on the system if 6,300 MW of gas-fueled generation became at risk due to fuel shortages during winter peak conditions. The RNA found that if these generators are unavailable during a peak winter in 2032, reliability would be diminished but still within the loss-of-load-expectation criterion. However, reliability would not meet statewide system margin under expected winter weather conditions by winter 2031-32, presenting a significant future risk.
The ISO told the committee it made small changes in response to stakeholder comments and questions since the second draft of the RNA was presented at the Sept. 1 TPAS meeting. (See “RNA Draft Report Finds No Immediate Needs,” NYISO Proposes Fixes for Interconnection Backlog)
The ISO plans to bring the RNA to votes at the Operating Committee Oct. 13 and the Management Committee Oct. 26 before submitting it to the NYISO Board of Directors for final approval in November.
AUSTIN, Texas — The Gulf Coast Power Association’s 37th annual fall conference, held in-person for the first time in three years, drew 685 registered attendees here last week. Strangely, that was the exact number of registrations the GCPA had for the same event in 2019.
When not renewing friendships and sharing handshakes and embraces with those they hadn’t seen in years, attendees were treated to panel discussions among lawmakers, market participants and industry experts on the ERCOT market, an oral history of the Texas grid operator, and a reenactment of the historical debates between Abraham Lincoln and Stephen Douglas.
Taking it all in was freshly minted ERCOT CEO Pablo Vegas, a surprise guest to the proceedings in just his second day on the job. He was shepherded during the conference’s first full day by Bill Flores, vice chair of the ISO’s Board of Directors. Vegas listened intently as the Joneses — Sam, ERCOT’s first CEO; Brad, its retiring interim CEO; Liz, Oncor’s regulatory affairs lead; and Dan, a respected energy consultant who helped create Texas’ competitive market — reminisced about their roles in ERCOT’s various market designs and how often their paths crossed at the ISO, Public Utility Commission and elsewhere in the industry.
Vegas seemed aware of the high expectations he faces and the responsibility he is undertaking.
“To think about the history of this institution that I’m now going to have the privilege to lead … each of the leaders up there have played a significant role in making and [preparing ERCOT for change],” he told RTO Insider. “It’s not so much a passing of the torch but just continuing to make sure that we all understand where it’s been, why it’s lit, and why that’s important.
“It’s just exciting to be a part of the next big change and big evolution that ERCOT has been going through, decade after decade over the years, and it’s great to be a part of this one. I can tell that there’s going to be a lot of help from the industry, a lot of suggestions, and I’m just looking forward to working through all of those together with such a great team.”
Introduced by Flores for a few opening comments to the audience, Vegas said he was “thrilled … honored and privileged” to be joining Team ERCOT and that he looked forward to working with the “incredible professionals” in the ballroom. Vegas invited those he did not know from an earlier stint in Texas to come meet him. (See Vegas Plans to ‘Engage Heavily’ in ERCOT Changes.)
“All I can say is, ‘Wow, what a time to be coming back into Texas,’ with what’s going on in the market and what’s going on in the economy,” he said. “I can’t remember a more exciting time to be in this industry.”
Flores Says Vegas ‘Checked All Boxes’
Flores, who led the ERCOT board’s search committee for Jones’ successor, told RTO Insider that Vegas checked all the boxes the group was looking for. He said Vegas stood out early after the committee initially identified 107 candidates to become the grid operator’s fifth full-time CEO.
“It quickly came down to a small handful of people. We were looking for somebody with an engineering technical background, somebody with good leadership attributes, including a selfless servant leadership style. We were looking for someone who had senior executive experience … and to a lesser extent, somebody who already had experience with the Texas market,” Flores said, nodding to Vegas’ two years as COO of American Electric Power’s AEP Texas subsidiary.
Told that it appears he has been a quick learner of ERCOT’s operations and functions, Flores said, “I’ve been a real nerd about this.
“I’ve read a lot of books; I have listened to tons of podcast. I spend a lot of time with Woody [Rickerson, ERCOT’s vice president of system planning and weatherization] and the gang, and I’m still not done yet.”
A five-term Republican member of the U.S. House of Representatives, Flores was appointed to the ERCOT board last year and serves as its vice chair. A certified public accountant, he has a background in the oil and gas industry. During his keynote address, Flores warned of the danger of relying on a single fuel, as Europe has discovered with Russian natural gas after its invasion of Ukraine. However, he also noted he is the largest residential solar user in his home county, and he extolled an “all-of-the-above” approach to ERCOT’s fuel mix.
“One of the things I’ve noticed in environmental analysis today is that when you look at fossil generation, it’s looked at from end to end,” Flores said. “When you’re looking at other forms of generation, it’s just from when you turn it on to when you turn it off. Every source of generation needs to be looked at end-to-end on the environmental and emission scale.
“The bottom line from a policymaking perspective is that we need all-of-the-above solutions that have balance, that follow the laws of nature with respect to electricity, that follow the laws of economics,” he said. “We’ll have better policy outcomes when we follow those laws, versus what we as humans think we can do.”
GCPA Members Honor Jones
GCPA members and conference attendees honored Brad Jones with an extended standing ovation after his panel discussion with three other Joneses ended.
GCPA President Mark Dreyfus, who represents commercial consumers on ERCOT’s Technical Advisory Committee, recalled his more-than-25-year association with Jones. It began when Dreyfus was a PUC staff member and Jones was the “lowest guy on the totem pole” for TXU, Vistra’s predecessor.
“His job, as far as I could tell, was to chase after us following a PUC open meeting to find out exactly what the commissioners had decided so he could report back,” Dreyfus said. “I really liked that Brad Jones back then.”
Jones rose through the ranks at TXU and played an integral role in designing ERCOT’s competitive market. Like Dreyfus, Jones presided over GCPA. He joined ERCOT as COO and then “packed up his cowboy boots,” as Dreyfus said, and left Texas for a short stint as NYISO’s CEO.
“But I know he was lonely for home and family,” said Dreyfus, who visited Jones in Albany, N.Y. “He treated me like family and treated me to an insider’s tour of the city: well-cooked sirloin, beer pong and a reggae show.”
Jones left NYISO in 2018 and retired to his home in Austin. That is, until the February 2021 winter storm came within minutes of collapsing the Texas grid, leaving ERCOT and the industry in “disarray,” as Dreyfus put it.
“Who would step up and take on the responsibility of leadership? I can’t think of anyone other than Brad, who brought his experience in the industry, experience in the New York ISO, and that demeanor he has which is so successful with our industry members at the legislature and with the membership of GCPA,” Dreyfus said. “We don’t have a gift card or flowers or custom GCPA cowboy boots, but we do have a reception immediately following where I hope you will take a minute to thank Brad.”
Jones could do little more than laugh and nod his head in appreciation.
“Brad has done a great job of readying ERCOT for this next level of change,” Vegas said after the applause settled.
“[Jones] stepped up at a really critical time for the 26 million Texans that are served by the ERCOT part of the Texas grid and to help keep the team together,” Flores said. “He worked with policymakers and regulators to keep the lights on, so we owe him.
McAdams: Give Market-based Solutions a Chance
PUC Commissioner Will McAdams gave the conference attendees a sneak preview of the commission’s proposed Phase II market design, which the commission continues to plan for a mid-November release. He said the commissioners recognize that the grid of the “very near future” will consist of more renewable and intermittent resources than dispatchable capabilities.
“And that’s fine. We believe, I believe, to cover the variability of intermittent output, we must ensure that sufficient quantities of dispatchable power cover system needs during forecasted high risk periods,” he said in a keynote address. “This serves as the basis of what we’re discussing now. This will allow us to reduce our out-of-market actions like [reliability unit commitments] and replace them with market-based solutions. [As other speakers suggested], this framework will be based on market principles, which I hope will represent the consensus of the commission.”
McAdams said the Phase II market adjustments will encourage dispatchable generators to maintain their facilities, and, if necessary, to replace retiring units with new generation. But, he reminded his audience, the PUC can’t guarantee that new generation will be built.
“We can influence markets, but we cannot command them to deploy capital,” McAdams said. “If policymakers believe that they require a guarantee that new generation be built in order to meet growing system demands, then a policy must be taken up and considered by the state legislature. It is a crossroads … one route stays the course with markets and market-based solutions. The other would instruct the PUC to assume a more command-and-control posture in how electricity is generated and delivered within ERCOT.”
Historically, markets, collective viewpoints and their stakeholders are best suited to adapting to changes, he said.
“As such, I believe that the best way to restore the public’s trust and confidence in our grid is for the public utility commission, ERCOT and our market participants to work together to demonstrate that we can build a policy to achieve maximum grid reliability,” he said, “and at a sustainable cost level to Texas consumers that may endure challenges by the naysayers and detractors and demonstrate to the legislature that this is a market worth saving.”
Texas Politicos Wait on ERCOT Redesign
Count Texas lawmakers among ERCOT stakeholders who are looking forward to the PUC’s release of its Phase II market design, expected in mid-November. The Texas legislature opens its five-month biennial session Jan. 10, and legislators have asked to vet the PUC’s market design before the ISO’s staff begins to implement it. (See Texas Lawmakers to Vet ERCOT Market Redesign.)
“For the most part, we’re all waiting for the next big change,” State Sen. Nathan Johnson (D) said, noting discussions taking place within several Texas energy advisory and reliability committees. “I don’t mean to be dismissive of it being a lot of talk, but because it’s a very important conversation, but we have yet to see the results from it. We have a variety of perspectives. We have competing viewpoints … but as we move into the legislative session, and as we come out of the legislative session, we’re going to have to have some clarity.”
Johnson said legislators, who passed several laws related to the grid’s near-collapse during last year’s winter storm, expected the market design to have been further along that it is now. (See Abbott Signs Texas Grid Legislation into Law.)
“As much fun as it is, this is hard. We don’t have the answer yet,” he said. “We need the confidence of the investors. We’re not going to get there with a bunch of day-ahead ancillary services. We’re going to see some form of a capacity market in our energy-only market. There’s going to be an element of predictability and an agreed-upon predictability standard.”
State Rep. Phil King (R), who represents a gas-rich district, said electric power has been the most complex, competitive and diverse issue he has dealt with in his 24 years at the Capitol.
“I think this is going to be the second most substantive change we’ve made in how we do all this since 1999 … we created a competitive market that was the envy of the world,” King said, referring to Senate Bill 7 that deregulated ERCOT’s wholesale and retail markets.
“From my perspective, it’s how do we make sure that we have enough gas-fired generation that can be built in a way that companies can make a reasonable profit? But how do we incentivize building enough gas-fired power without stepping over that line and entering back into a regulatory market?” King asked. “Renewables have a big place in Texas. I think we can have a really hard discussion about how much that is. Relative to the amount of dispatchable electricity, I think there’s too much. And so how do we incentivize from a financial perspective and a regulatory perspective for gas-fired plants to be built without stepping off that cliff and losing the competitive market?”
“We have to be agnostic about the future,” countered State Rep. Donna Howard (D). “Obviously, we need to have resiliency, and we need to have reliability. It needs to be affordable. We need to have dispatchable [generation] and we need to have predictability. We know that renewables, of course, are predictable [to forecast]. Gas is volatile. We are so fortunate to have the thermal resources that we have … We want to make sure that whatever the market redesign ends up being, that it is going to incentivize whatever it is that will give us the power we need when we need it.”
Lincoln-Douglas? Try Barnes-Stover
Apex Clean Energy’s Mark Stover and NRG Energy’s Bill Barnes did their best to recreate the famed 1858 senatorial debates between Abraham Lincoln and Stephen Douglas, albeit in condensed form. Rather than conduct seven three-hour debates, the two settled for a 30-minute discussion over whether transmission planning and regulatory reforms to relieve congestion are compatible with regulatory design changes to retain and incentivize dispatchable generation in ERCOT’s energy-only market.
“I have made many sacrifices throughout my career for the entertainment of the GCPA audience. This might be a new low or new high, so I hope you guys appreciate this,” Barnes said, donning a fake beard and what passed for a stovepipe hat in his role as Honest Abe. “Abraham Lincoln was like nine feet tall, so you’re going to have to use your imagination.”
“Bill definitely wins the costume category,” admitted Stover, who wore a vest and a long coat. “But at the very least, Bill and I got a jump on our Halloween shopping this year.”
Stover, Apex’s director of state affairs, said in his address that market design and transmission reforms are compatible. If done right, he said, ERCOT’s transmission planning process “can actually bolster our efforts to increase reliability on the ERCOT system, something every stakeholder wants, including the renewable energy sector.”
“If the transmission projects can deliver new wind, solar, storage and, yes, natural gas paired with something that we don’t talk a lot about, increased efficiency and demand response, we can deliver the same amount of power or more at a lower cost than existing fossil assets or new planned large thermal assets,” Stover said. “We need to move away from our just-in-time regime, which is increasing costs on consumers and unnecessarily straining our power grid and keeps a range of benefits from flowing to consumers.”
“Hogwash!” Barnes, NRG Energy’s senior director of regulatory affairs, bellowed after Stover’s close.
“Transmission planning processes and regulatory reforms that create preference for transmission development fundamentally conflict with the foundational principles of an energy-only market and work to defeat the incentives to retain and attractive dispatchable resources,” Barnes said. “Transmission congestion is a design feature of LMP-based markets, not an excuse to endlessly build more transmission lines. These deliberate pricing differences allow for the competitive market to address transmission bottlenecks through redispatch of generation and, if allowed to persist, through private investment, rather than regulated costs to captive ratepayers.”
The audience judged the debate a draw. Douglas narrowly won election to the Illinois U.S. Senate seat up for grabs after the debates. Two years later, though, Lincoln won the big prize when he defeated Douglas in the 1860 presidential election.
Vistra’s Haley Receives GCPA Award
GCPA presented Vistra’s Ian Haley with its emPOWERing Young Professionals Award, as selected by the organization’s board. The award is presented annually to an individual under the age of 40 who has achieved excellence in the power industry, making unique contributions to the success of the electric power market and serving as a role model and leader for others.
Vistra’s senior director of regulatory policy, Haley was described as “an ardent participant in the stakeholder process.” He represents Vistra subsidiary Luminant on TAC and works on several other ERCOT committees, vice chairing the Supply Analysis Working Group.
“I cannot tell you how much I appreciate this,” Haley told the audience. “I’m deeply honored, even though quite a few of you have told me there’s no way I’m under 40. I feel extremely fortunate to work in an industry that I find so interesting and have the opportunity to work with so many people I consider friends.”
“He’s a fellow Tulane graduate,” Vistra CEO Jim Burke said in introducing Haley. “You probably didn’t read that in the bio, but good people come out into Tulane University.”
“Ian has a knack for reaching out across the aisle in the ERCOT stakeholder process and is an adept negotiator,” Ned Bonskowski, Vistra’s vice president of Texas regulatory policy, said in a statement. “Some of his strongest work is when he is forging consensus across disparate stakeholders on contentious issues.”
The award’s nomination criteria includes career progress, industry involvement, leadership development, role model for other young professionals, and expertise, passion and the ability to inspire others.
Stakeholders Endorse 2022 Reserve Requirement Study Results
The PJM Planning Committee on Oct. 4 voted by acclamation to endorse the results of the 2022 Reserve Requirement Study, which would reset the forecast pool requirement (FPR) and installed reserve margin (IRM) for the next three years and determines a recommendation for 2026/27. It would also set a winter weekly reserve target (WWRT) for the upcoming season.
The recommended IRM remains at its current 14.9% for 2023/24 before falling to 14.8% the following year and declining to 14.7% for 2025/26 and the next year. Last year’s study recommended a similar decline, though moved up a year in advance. (See “Reserve Requirement Study Recommends Raising IRM and FPR,” PJM MRC/MC Briefs: Sept. 21, 2022.)
Driven largely by scarce projected capacity available for import during peak season, the recommended FPR for 2023/24 increases under the study, going from 1.0901 in last year’s analysis to 1.093 in this year’s. That moves downward to 1.0926 in 2024/25 and falls to 1.0918 for the following two years.
The study recommends a 27% WWRT during the peak winter month of January, 23% for February — the next highest consumption winter month — and 21% in December. The figure is used to aid PJM in planning outages.
The IRM and FPR are set to be reviewed by the Markets and Reliability and Members committees in October through November and by the Board of Managers in December. The WWRT is scheduled to be voted on by the Operating Committee in November.
Load Forecast Model Recommendations Discussed
PJM Senior Analyst Andrew Gledhill reviewed the recommendations under consideration for the development of a new load forecast model.
The recommendations are derived from a report produced by the consulting firm Itron, which was contracted in April to perform a model review. They include:
replacing annual/quarterly end-use indices with the use of monthly/daily indices, which would allow for the use of more recent data that are more representative of current patterns. Monthly models would also result in heating and cooling figures that are more reflective of the amount of weather variation in each month.
continuing with the current weather simulation approach, but with a shorter historical lookback period of 20 years and seven rotations; 27 years and 13 rotations are currently used.
replacing daily models with hourly load models, which would allow for more flexibility to incorporate future trends and technology, particularly the impact of solar and electric vehicles.
adjusting loads for new technologies through the simulation process, reflecting current knowledge about how behind-the-meter solar and EVs behave and layering those understandings into simulations.
incorporating climate change into long-term forecasts and evaluating long-term temperature trends for each planning zone.
Gledhill said PJM is in the process of evaluating the first four recommendations for the 2023 load forecast and will report its progress to the Load Analysis Subcommittee. The fifth recommendation is expected to take additional thought and engagement with stakeholders, with a tentative plan to incorporate it into the 2024 load forecast.
Poll Opened to Gather Support for Packages on CIR for ELCC Resources
The PC is holding a nonbinding poll to gauge support for the six proposals currently on the table to address capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources. Opened after the committee’s meeting, the online poll closes Tuesday at noon.
The poll asks respondents to say whether they can support each of the packages and, if not, to indicate which of the design components they are against. The packages are composed of five overall components: CIR request policy; CIR verification, testing and retention policy; CIRs in ELCC methodology and accredited unforced capacity calculations; implantation and effective dates; and transition mechanisms.
The sponsors of the packages outlined the changes that the proposals have undergone over the past few months and discussed the effects each would have.
Tom Hoatson, director of Mid-Atlantic policy for LS Power, said his company’s package could continue to change depending on the results of the poll, particularly its CIR request policy, which he said was written to achieve a consensus in prior special sessions and relies upon the same language as one of the PJM packages. Stakeholders questioned what the impact would be should a generator request a higher CIR level than it can deliver under that language.
Responding to questions about the impact of the packages on the cost and timing of the RTO’s interconnection queue restructuring effort, PJM’s Jonathan Kern said the proposals that incorporate higher CIRs into the mix would have an impact on the queue.
Economist Roy Shanker said that any time the order of the queue is changed and applications are moved ahead of each other, the cost allocation changes alongside it, and those who are “jumped over” will face increased costs. The current structure being considered would result in approximately 7,200 to 7,300 MW of projects being given priority status, which would result in an estimated $2 billion cost for applicants in the fast track and Transition Cycle 1, he said. The costs remain unknown for those in Transition Cycle 2, but Shanker said they could potentially face billions in increased costs.
“As long as you don’t change that order, you don’t change that cost,” he said.
Transmission Expansion Advisory Committee
$13M in Tx Projects Discussed
At the Transmission Expansion Advisory Committee meeting that followed the PC’s meeting, several transmission owners presented supplemental projects for the PJM Regional Transmission Expansion Plan.
Baltimore Gas and Electric is planning the replacement of its High Ridge 230-1 transformer, installed in 1960 and in deteriorating condition, at a $7.4 million cost.
American Electric Power meanwhile has several facilities operating on a former practice of applying a double multiplier in the ratings of facilities that connect in a configuration where flow could split between two paths in a station. The company is in the process of applying single-multiplier ratings to all its facilities, but four were flagged in PJM’s 2025 RTEP analysis that could result in violations of NERC reliability standards.
The work would include replacing breakers and associated equipment at the 765/345-kV Marysville transformer, 345/138-kV East Lima transformer, 345-kV Jefferson-Clifty Creek line and 138-kV Olive-New Carlisle line at a $5.92 million cost.
Residential solar-plus-storage systems can in some cases meet nearly all of a home’s “critical load” — including heating and cooling — during extended power outages, according to a study from the Lawrence Berkeley National Lab.
But system performance depends on a variety of factors, including the size of the system, where in the U.S. the home is located, and whether the home uses electric-resistance space heating such as baseboard heaters. The study, which was based on models and simulations, described loads from electric resistance heating as “quite large and more difficult to serve.”
The impact of electric resistance heating was one of the surprises to come out of the study, according to Galen Barbose, a research scientist in the Electricity Markets and Policy Department at Lawrence Berkeley National Laboratory and one of the study authors.
“That was far and away the biggest determinant to the results,” Barbose told NetZero Insider.
Berkeley Lab researchers collaborated with scientists from the National Renewable Energy Laboratory on the solar-plus-storage report, which was published last month. Barbose and Berkeley Lab colleague Will Gorman hosted a webinar last week to discuss the study’s findings.
Behind-the-meter solar-plus-storage systems are gaining popularity among residential and commercial building owners, Barbose said during the webinar.
“That trend is being driven by a variety of factors, but certainly one of the major ones has been concerns around grid reliability and resilience and customer interest in using these systems for backup power,” he said.
Yet there has been little research into how well the systems perform as backup power during extended outages, a question the researchers sought to address.
Simulating Outages
The researchers modeled solar and load profiles and then simulated battery storage dispatch during power interruptions. The study looked at outages of a day or longer. These “synthetic” power outages were examined in every county in the U.S. and for every month of the year.
The study primarily analyzed the expected performance of systems where solar provides all of a home’s annual energy consumption, which Barbose said is “pretty typical” for the systems. Systems with 15 kWh or 30 kWh of storage were compared.
The analysis showed the systems could provide enough backup power to meet “limited critical load” in single-family, detached homes. That load includes refrigerators, lighting, well pumps, and power for computers, internet and cell phones.
“Under a limited critical load scenario that excludes heating and cooling, a small [solar and storage system] with just 10 kWh of storage … can fully meet backup needs over a three-day outage in virtually all U.S. counties and any month of the year,” the report stated.
But if the loads are expanded to include heating and cooling, more variation emerges. A system with 15 kWh of storage would meet a projected 85% of critical load including heating and cooling, averaged across all counties and months. A system with 30 kWh of storage would meet 96% of load on average.
With heating and cooling included in load, the backup performance of solar plus storage dips in the winter in the Southeastern U.S. and the Pacific Northwest, regions where electric resistance heating is common, the study found. In the summer, backup performance falls in the Southwest.
In cities such as Chicago and Boston, many homes use gas furnaces for heating, so wintertime heating doesn’t add that much to the electric load, the researchers said. Furnace fans, which often run on electricity, may contribute to the load.
The researchers plan to take a closer look in the future at backup-system performance in homes with electric heat pumps.
Solar Plus Storage Confidence
The overall results may give homeowners more confidence in solar plus storage as a backup power system, especially if they’re primarily interested in maintaining power to a limited load set without heating and cooling, Barbose said in an email after the webinar.
“In cases where customers want to provide backup to heating and cooling loads, the report shows that this may be possible, but requires careful attention to the size of those loads,” Barbose said.
And providing backup for heating and cooling is easier when homes are energy efficient, he said.
Another surprise to come out of the study was that in most cases, the length of the power outage had little impact on how well the solar-plus-storage systems could maintain backup power.
Average load served dropped from 96% on the third day of the outage to 92% on the 10th day, according to the simulations for a 30-kWh storage system that included heating and cooling. That indicates solar energy would largely be able to replenish battery storage that became depleted.
But the longer an outage lasts, the greater the chance of experiencing a cloudy day or increased load, decreasing the percentage of load met, the researchers noted.
In another piece of the study, researchers looked at how well solar plus storage would have fared as a backup system during outages caused by 10 actual weather events.
During a winter storm that hit Oklahoma in October and November 2020, with outages lasting up to 12 days, the study found a median load served of 98% with a 10-kWh battery and 100% with a 30-kWh battery.
The study calculated a median load served of 100% for either a 10-kWh or 30-kWh battery during the October 2019 public safety power shutoff in Northern California. The outage lasted for up to 4.6 days.
But for Hurricane Florence, which caused outages of up to 10 days in North Carolina in 2018, median load served as calculated in the study was 68% with a 10-kWh battery to 76% with a 30-kWh battery.
“Performance can vary considerably over the course of the event,” researchers noted. For example, solar plus storage performance suffered from lack of sunshine during the first days of the outage caused by Hurricane Florence but recovered in later days.
