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.
MISO’s final Transmission Expansion Plan for 2022 (MTEP 22), comprising 382 projects totaling $4.3 billion, earned a hesitant nod from the stakeholder-led Planning Advisory Committee last week.
Four of 11 MISO sectors voted electronically for the annual transmission expansion package while five sectors abstained, some with criticisms. None of the sectors voted to reject MTEP 22.
MISO’s Transmission Owners, Municipals and Co-ops, Affiliates and Independent Power Producers sectors voted in favor of the plan. The RTO’s State Regulatory, Public Consumers, Eligible End Use Customers, Transmission Developers and Environmental sectors abstained.
The Power Marketers and Coordinating sectors didn’t participate. It’s not unusual for the End-Use, Public Consumers, Power Marketers and State Regulatory sectors to abstain or refrain from casting ballots in PAC voting matters. It is unusual, however, for abstentions to outnumber votes in favor of MTEP package recommendations.
The Transmission Developer sector said it abstained because MISO’s $3 billion spend in “other” category projects is large and the grid operator “has not adequately considered regional alternatives that may be more efficient or cost-effective solutions to the identified needs.” The developers also said there’s currently “minimal ability for MISO stakeholders to meaningfully participate in the planning” of projects in the “other” category.
MTEP 22 contains 69 generator interconnection projects costing $547 million; 41 baseline reliability projects at $545 million; and 270 other projects at almost $3.2 billion. The other project category includes TOs’ reliability projects and work needed for load growth and to address existing facilities’ age and condition. Other projects have become the lion’s share of MTEP spending since the 2018 cycle.
The Environmental sector said it took exception to language in MTEP 22’s report. It said MISO should clarify that the changing resource mix “is not driven solely by carbon-reduction goals” and said staff shouldn’t exclusively use natural gas resources as an example of a solution for more available resources.
In the report, the grid operator says it has a responsibility to reliably transition from “today’s resource mix” to “our members’ stated carbon-free goals.” The environmental representatives said MISO should add that the transition is also driven by “economics, state and utility policies, and consumer preferences.”
“If MISO refuses again to meaningfully address these concerns, then we request that the System Planning Committee of the Board of Directors require MISO to address these requests in a meaningful way prior to sending the draft MTEP 22 report to the full Board of Directors,” the sector wrote.
The annual transmission package now advances to the board’s System Planning Committee for consideration. The full board will then vote on MTEP 22 in early December.
Entergy Arkansas’ $122 million Sandy Bayou 500/230-kV substation to accommodate load growth is this year’s most expensive project. It will tap into the utility’s existing Driver–Shelby 500-kV line.
That second-most expensive project is Ameren Missouri’s need for $120 million of new static synchronous compensators necessary to reinforce the system when the utility retires its 1.2-GW Rush Island coal power plant. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)
MISO project manager Sandy Boegeman said MTEP 22’s costs are typical when compared to other recent MTEP packages. She said age and condition drove many of the reasons behind the projects.
MTEP 22 devotes $2 billion to substation work, $1.4 billion to line upgrades, $440 million to new lines, $146 million to voltage devices and $109 million to transformer projects.
The developers behind the Grain Belt Express asked that MISO incorporate its line and other “advanced stage merchant transmission” into annual transmission planning assumptions. (See Invenergy Announces Grain Belt Express Expansion.)
Boegeman reiterated MISO’s stance that it doesn’t include merchant transmission projects in modeling until the projects execute interconnection agreements with MISO or until they have been included in a relevant integrated resource plan.
A group of New England suppliers is raising worries about the costs of the cost-of-service agreement between ISO-NE and the Mystic Generating Station heading into what many believe could be the priciest winter for gas in recent memory.
In a letter to ISO-NE officials dated Sept. 29, the group of load-serving entities pointed to the high costs of the agreement for its first few months of existence this summer: $13 million for June and $48 million for July. Heading into this winter, they warn, the “costs could balloon to levels not contemplated in 2018,” when the agreement was put into place.
The suppliers said they don’t take issue with the need for the agreement, which is staving off the retirement of Mystic, a critical gas-fired plant in Massachusetts, until 2024. But they do want to try to protect themselves and consumers from the costs of the program.
“We have grave concerns regarding the winter months, when gas prices will be at their highest, and the costs that we could face under the agreement,” the companies wrote. “No one in 2018 could have predicted how much more volatile and unmanageable hedging these costs would become considering world events.”
To try to manage the risk, the companies asked ISO-NE to provide more information and transparency about the agreement, including a cost estimate for the whole agreement and a cost estimation worksheet for its first months.
“The LSE group recognizes the challenges ISO-NE has faced that led to the Mystic COS agreement and the hard work that ISO-NE is doing to prepare for this winter,” they wrote. “The primary goal here is not to thwart those efforts but instead to work together to mitigate the costs associated with the Mystic COS agreement as much as possible.”
The companies are Brookfield Renewable Trading and Marketing, ENGIE Energy Marketing, NextEra Energy Marketing, Shell, Vistra and Vitol.
At the NEPOOL Participants Committee meeting on Thursday, ISO-NE COO Vamsi Chadalavada promised that the grid operator will work with them.
“ISO understands and appreciates the gravity of the situation,” he said.
Chadalavada said ISO-NE experts will present on the administration of the contract at the Markets Committee this week. He also said the grid operator is planning to do a scenario analysis to help inform cost estimates for the winter months. And he said the RTO is reaching out to LSEs, states, consumer advocates and transmission owners to talk about possible changes to cost allocation for the second year of the agreement.
Other PC Action
It was a busy day for the PC, which also saw a number of significant votes and presentations.
Chadalavada presented the latest iteration of the RTO’s 2023 work plan, which includes intensifying focus on the development of a day-ahead ancillary services market and resource capacity accreditation. Both will be regular topics of NEPOOL meetings in the coming months, and the grid operator is planning to file to FERC on both by the end of 2023.
Work on energy adequacy, including considering changes to the Inventoried Energy Program, is another highlight.
The committee also approved ISO-NE’s proposed installed capacity requirement values for Forward Capacity Auction 17, despite longstanding stakeholder frustration over the methodology for calculating ICR and the assumptions about imports from New York.
The systemwide demand curve for the 2026/2027 capacity commitment period | ISO-NE
The approved ICR for the 2026-2027 capacity period is 31,306 MW, and the net ICR is 30,305 MW.
The PC also signed off on the 2023 budgets for ISO-NE and New England State Committee on Electricity.
SPP has posted a Markets+ draft service offering that lays out the RTO’s proposal to “modernize and enhance” operation of the Western grid.
The document provides the proposed governance structure, market design and other key features of Markets+. SPP describes the service offering as providing Western Interconnection utilities that aren’t ready to pursue full RTO membership a voluntary, incremental opportunity to realize significant benefits.
The governance and design principles are based on feedback SPP has received from the Western utilities with which it hopes to partner. Participants have until Oct. 28 to provide additional input to the service offering.
The grid operator said the design sessions have narrowed the day-ahead market’s basic structure to two possible implementations: a voluntary, financial market with financially binding day-ahead positions that include physical instructions for resources to start and stop, and a multistage process where a reliability-based, physical resource commitment occurs followed by a purely financial and voluntary day-ahead market.
SPP will host a Markets+ development update webinar Nov. 1 to discuss funding the tariff development for the offering and commitment agreements. An in-person meeting of the Markets+ development group will be held Nov. 15-16 in Westminster, Colo., before the final service offering is released.
RTO staff and Western utilities will continue their work in two phases. First, potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents. The second phase will begin with FERC approval.
SPP said it will take 21 months to develop and prepare the FERC package at a fixed cost of $9.7 million. It said staff will work with stakeholders to develop a cost allocation approach for the startup costs before the final service offering is issued. Potential participants will pay a monthly rate of $500,000 to support the responses, technical analysis and research necessary to gain final FERC approval.
Eleven Western entities have already told SPP they are committed to working with the grid operator to build a Western market that includes “both a workable governance framework and a robust market design.” (See SPP’s Markets+ Offering Attracts 6 More Western Entities.)
Staff Drafting JTIQ Policy
SPP staff told stakeholders they are drafting the governing language to allocate costs for any projects identified in their joint targeted interconnection queue study with MISO. The grid operators plan to assign 90% of the $1 billion study’s portfolio to interconnection customers and the remaining 10% to an aggregate of their load, but they were met with some pushback during a Sept. 30 joint stakeholder meeting. (See Stakeholders Not Sold on JITQ Projects’ Cost-Sharing Plan.)
“We’re trying to solidify the principles to where we can build governing language around them and then move it into the regulatory arena,” SPP’s Neil Robertson, coordinator of system planning, told the Seams Advisory Group Friday.
Staff said they plan to post a policy paper this week designed to gain approval for the cost allocation mechanics and methodology that the SPP region will use. They have scheduled meetings with state and federal regulators to secure their buy-in and hope to get approval from the Regional State Committee in January. The goal is to make the necessary changes to the joint operating agreement and file with FERC in the first quarter.
Air Products (NYSE:APD) plans to spend about $500 million to build a plant in northern New York that would produce 35 metric tons of liquid hydrogen a day for use as vehicle fuel, the company announced Thursday.
The Allentown, Pa.-based industrial gas supplier is siting the facility in Massena, near the New York Power Authority’s St. Lawrence-FDR hydroelectric plant. NYPA has already allocated some of its low-cost power to the proposed green hydrogen plant, which would go online in 2026 or 2027.
Air Products said in a news release that the project budget will rely on incentives from state and local governments and the recently passed federal Inflation Reduction Act.
Liquid hydrogen distribution and dispensing operations are planned beside the production facility. Air Products is also considering construction of a network of hydrogen vehicle fueling stations across the Northeast, in part to fuel its own trucks: The company has committed to converting its roughly 2,000-truck global fleet to zero-emissions vehicles powered by hydrogen fuel cells.
“This project is another demonstration of our leadership role in the low-carbon hydrogen and the hydrogen for mobility markets, and New York state’s and IRA incentives will continue to encourage hydrogen’s key role and our investment in the energy transition,” Air Products CEO Seifi Ghasemi said in the news release.
The company said it expects demand for green hydrogen in the Northeast to grow dramatically with New York’s adoption of the federal Advanced Clean Trucks rule and New York’s leadership of a multistate effort to become a designated hub through the federal Regional Clean Hydrogen Hubs program.
The New York State Energy Development Authority has requested another year to set up the system of renewable energy credits that is part of the state’s plan to bring clean energy into New York City.
The Public Service Commission had set an Oct. 11 deadline for the implementation plan for the Tier 4 program of the Clean Energy Standard. But in an Oct. 7 letter to the PSC, NYSERDA said Tier 4 is a complex and all-new aspect of the state’s clean-energy strategy, with many requirements and many involved parties.
Because energy delivery from the two Tier 4 contracts is not expected until 2026 and 2027, NYSERDA wrote, there is time for a longer, more thoughtful process. It asked PSC to push the deadline back to Oct. 11, 2023.
Tier 4 was designed to increase use of renewable energy in New York City; while the generation mix in most of the state leans heavily toward clean power, the city itself relies almost entirely on fossil fuel-generated electricity.
The two approved Tier 4 projects — Clean Path New York and Champlain Hudson Power Express — are HVDC transmission lines that would deliver thousands of megawatts of solar, wind and hydro power to the city from Canada and upstate New York. (See NYPSC OKs 2 Huge Clean Energy Projects for New York City.)
Two environmental advocacy groups told RTO Insider on Friday that a one-year delay would not be a setback in the state’s clean energy transition.
Conor Bambrick, director of climate policy at Environmental Advocates of New York, noted that Champlain Hudson itself had pushed its target completion date back from 2025 to 2026 because of supply chain constraints and delays in the regulatory process.
Anne Reynolds, executive director of Alliance for Clean Energy New York, said the extension NYSERDA is seeking does not entail the projects themselves.
“NYSERDA apparently needs more time to iron out some complex issues with how the contracts will be managed and how the renewable energy credits from the projects will be bought and then sold, but this delay will not affect the two Tier 4 projects contracted to deliver clean power to New York City,” she said via email. “This administrative delay shouldn’t affect the project schedule, and the operation date for the projects is still three to five years out.”
In its request for an extension, NYSERDA said development of the implementation plan depends on resolution of issues beyond its direct control. It said its staff are meeting regularly with external consultants, NYISO working groups and Tier 4 sellers’ teams to develop the implementation plan.
State regulators and consumer advocates urged FERC Thursday to order the creation of independent transmission monitors and other measures to increase oversight over transmission owners’ planning and spending.
Multiple speakers at FERC’s daylong technical conference on transmission planning and cost controls said FERC action was needed to address an “information asymmetry” in transmission planning and the TOs’ increasing spending on local transmission projects that face little oversight (AD22-8).
In PJM, for example, transmission owners’ spending on local “supplemental” projects since 2014 has dwarfed that on baseline projects meeting regional needs, which are vetted through the RTO’s Regional Transmission Expansion Plan.
PJM transmission owners’ spending on local supplemental projects that face little oversight has dwarfed that on baseline projects meeting regional needs since 2014.
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PJM
Independent Transmission Monitor
The commission heard from more than three dozen witnesses, many of whom said they supported the creation of independent transmission monitors to provide expertise enabling RTOs and state regulators to ensure their stakeholders’ transmission dollars are being spent most cost effectively.
Michael Haugh, director of analytical services at the Office of the Ohio Consumers’ Counsel, said consumer advocates don’t have access to enough information to ensure project costs are prudently incurred.
Robert Weishaar, McNees Wallace & Nurick | FERC
“We don’t know what we don’t know, and that’s a big issue. … We’ve found that more independence in these types of situations is better,” he said.
Haugh said an independent monitor would be particularly helpful in PJM for TO-proposed supplemental projects, where PJM’s only review is to make sure they do not harm reliability.
“We feel … an independent monitor would be able to look at these independently and see if there are competitive solutions that are better,” he said.
“Our view is that all transmission facilities over which the commission has jurisdiction should be planned by an independent transmission planner,” said Robert Weishaar, energy lawyer for McNees Wallace & Nurick, who represents industrial customers in MISO and PJM. He said an independent transmission monitor could have a standing set of engineers that could analyze and review projects from an objective standpoint.
Weishaar said for years there’s been a “somewhat artificial regulatory distinction” between local and regional transmission projects in terms of oversight, cost recovery and eligibility for competition.
Rhode Island Public Utilities Commission Chair Ron Gerwatowski | FERC
Rhode Island Public Utilities Commission Chair Ron Gerwatowski said someone “with the authority of the commission” involved at the start of a transmission planning process would create “a cost oversight which I believe does not exist in New England today.”
“It’s not so much the information because there are protocols that are put in place that are actually very helpful [to] anyone that has the expertise to look at it. But the question is, ‘Who’s looking at it?’” Gerwatowski said.
Gerwatowski said a monitor would introduce some degree of risk to today’s essentially no-risk rate system, which he said he believes is not FERC’s intent. “The way you recover transmission rates is: Spend the money; get the money. Spend the money; get the money,” he said.
Kentucky Public Service Commission Chair Kent Chandler said an ITM would provide benefits similar to that of independent market monitors in RTO markets.
Kentucky Public Service Commission Chair Kent Chandler | FERC
“I don’t think there’s anything, for instance, that the IMM in MISO or the IMM in PJM do to usurp state authority in relation to choosing our generation. … They provide us with an incredible amount of information in that regard. I can understand people saying it might be an extra layer of bureaucracy, but for many of these projects, it may be the only set of eyes [that would look at] the need and the planning. … I look at it as being an opportunity to provide any of us [regulators] evidence … an independent set of eyes who actually knows what they’re talking about.”
Henry Tilghman, speaking for the Northwest & Intermountain Power Producers’ Coalition, said regional independent transmission monitors would be more efficient than leaving the responsibility to states.
“The reality in the West is if you’re doing a regional transmission project, you’ve got four, maybe five, states plus probably a federal government agency, Bonneville Power Administration. And is it really more efficient to require each of those individual states to staff up to do that sort of independent analysis of the transmission proposals? Or is it more efficient to have a single entity who has the expertise who can provide each of the states consistent information about a proposed project? And I think it is.”
“We have an opportunity, I think, to manage the cost a lot better and the project activity as it’s being proposed,” said Randy Howard, general manager of the Northern California Power Agency. “Because right now, there’s just not a way for us to do that. … We just don’t get access early enough in the process to influence the prioritization of what’s important for reliability and resiliency. And obviously, through our wildfires and other activities, we’ve seen where some of our projects that we tried to impress upon those utilities that should be done earlier, weren’t done. And then consequences occurred.”
TOs Push Back
Witnesses representing transmission owners strongly opposed the ITM concept.
Carolyn Cowan Barbash, vice president of transmission development and policy for NV Energy, said an independent planner isn’t necessary in the West, where states are larger and regulatory processes are sufficiently transparent.
WIRES Executive Director Larry Gasteiger argued that sub-delegating the authority of FERC to independent transmission monitors would invalidate their independence. He said he was troubled by the expectation that FERC lend out its authority to a third party when the commission itself should have oversight authority over costs.
Charles Marshall, ITC Holdings | FERC
Charles Marshall, vice president of transmission planning for ITC Holdings, said his company offers a high degree of data visibility on its proposed transmission projects, no matter how small the price tag.
Also, he said, ITC cancels plans that internal reviews show are no longer needed.
“That’s not a tariff requirement; that’s something that we’ve committed to our stakeholders to do,” Marshall said. “We’re continuously internally reviewing the merits of projects that we’ve yet to commence construction on.”
Jeff Burleson, a senior vice president at Southern Co. (NYSE:SO), recalled an instance several years ago in which the utility was able to cancel a major transmission line it was planning through virtue of its vertically integrated structure.
Jeff Burleson, Southern Co. | FERC
“Effectively, all of our planners sit around the same planning table — generation planners, transmission planners, fuel supply planners — and we look at the alternatives,” he said. “And one of the alternatives we saw to this 90-mile, 500-KV line was siting generation close to the load.
“I don’t think an independent monitor would be helpful to us,” Burleson said. “I think it would just add an additional layer of bureaucracy.”
Attorney Jon Schneider, a partner in Stinson LLP who spoke on behalf of the Large Public Power Council, also expressed doubts about the ITM’s value in controlling costs.
“We have three institutions on the scene as we speak. We have [FERC], we have state commissions, we have RTOs and ISOs. And if we need a fourth institution, it does strike us that something’s sort of going wrong with respect to the oversight exercised by the folks that are already looking at this,” he said.
“If you improve the transparency of the processes, beef up staffs at the state and [FERC] and on the RTO level, we’re not sure that the ITM is cost beneficial with respect to cost oversight. We’re not unsympathetic to it … but we’re a little bit circumspect.”
Defining ITM’s Role
MISO Director of Expansion Planning Jeanna Furnish said FERC should consider whether it intends for an independent transmission monitor to be a one-stop solution and what its role will be in disseminating information, holding meetings and engaging consumer advocates and state regulators.
Furnish pointed to MISO’s ongoing long-range transmission planning effort, which considers a multitude of reliability needs.
“Is it actually appropriate to put all the eggs in one basket? … Are we talking about 350 projects and there’s capacity for this independent transmission monitor to think about alternatives for every single project? I mean, that’s a huge work effort,” she said.
“And that’s another question about how much would all of that cost,” Commissioner Willie Phillips agreed.
Commissioner Allison Clements said that while the set of responsibilities of independent transmission monitors is “not yet fully baked,” a monitor proposing alternatives to every single project “isn’t really the spirit” of what FERC is considering.
Robert Ethier, ISO-NE’s vice president of system planning, said an ITM could provide needed resources but that the model should not be that of the market monitors.
“There’s a need for more public planning ability, more public technical capability, but I’m not sure that an ITM reporting to [FERC] or … reporting to the ISO makes sense. If we have an ITM that reports to the states, I could understand that, because to me, what the states need are more resources to deal with the future. …
“We, in New England at least, are going to ask a lot more of the states going forward. We are going to look to them for guidance on public policy projects in a way that we never have before. And it frankly makes me nervous, the idea that they’re not going to have additional resources to help fill that role.”
Pallas LeeVanSchaick, vice president of Potomac Economics, the market monitor for MISO, NYISO, ISO-NE and ERCOT, said RTOs can’t be expected to provide independent oversight of transmission owners’ local projects.
“We’ve found that [RTOs are] extremely deferential to the concerns of the local transmission owners, and it’s just hard to see that they’ll be able to scrutinize things or ask questions or get them to look at alternative assumptions in the way that you would need,” he said.
FERC Authority Questioned
Glick asked Ari Peskoe, director of the Harvard Electricity Law Initiative and prolific social media commentator, whether he believes FERC has jurisdiction to require regions to establish independence reference monitors, joking, “[I] normally get great legal advice [from you] on Twitter.”
Peskoe said FERC has authority through Order 890, which was “intended to provide transmission customers and other stakeholders a meaningful opportunity to engage in planning along with their transmission providers.”
“There’s a lot of evidence that we’ve heard today and in the record, and as well as in the RM21-17 [Notice of Proposed Rulemaking on transmission planning] that that just isn’t the case right now. And so, I think an ITM could be a solution to that.”
Commissioner James Danly, who participated by phone and spoke little during the conference, disagreed.
“I’m not entirely sure that our jurisdiction is a complete, obvious case that we have the power to do these things,” he said. “I don’t see a whole lot about meaningful opportunities to engage in the Federal Power Act text. And even granting that we have the jurisdiction to do it, we still have requisite statutory showings where we have to show under [Section 206] that the rates are not [just and reasonable]. And applying universal solutions across every region — despite the actual rates that are the result in the planning processes — I think is probably violative of the statute’s requirements.”
Peskoe also said the commission could order monitors in non-RTO areas as well as organized markets. “The commission’s open-access rules apply to all utilities,” he said. “Assuming the commission believes it can still supplement its open-access policies, I believe they would apply to all utilities [and] transmission providers.”
Capacity Accreditation of ‘Performance-based’ Resources
Rensselaer, N.Y. — NYISOpresented the Installed Capacity Working Group/Market Issues Working Group Sept. 30 with a proposed new technique for setting resource-specific derating factors for “performance-based” resources such as intermittent generation and limited control run of river. The new technique would be used in conjunction with capacity accreditation factors (CAFs) — a measure of the marginal reliability contribution of “representative” generators for each capacity accreditation resource class (CARC), a differentiation based on technology and operating characteristics.
Comparison of difference, ratio & NYISO’s proposed UCAP methodologies | NYISO
The CAFs, which reflect characteristics such as energy duration limitations and correlated unavailability due to weather or fuel supply limitations, will be used in conjunction with resource-specific derating factors that reflect the difference in a unit’s output from the modeled profile of the CARC.
The new proposal seeks to address problems with other proposed methodologies that the ISO said can result in distorted calculations of performance-based resources’ unforced capacity (UCAP).
NYISO’s proposed average capacity factor ratio approach can result in distorted winter UCAPs for resources that have smaller winter capacity factors than annual CAFs.
An alternative, the difference approach, can result in zero or negative UCAPs for resources with lower annual CAFs than average capacity factors in the winter.
To address the shortcomings of the two methodologies, the ISO proposed first calculating UCAPs for each performance-based resource under each approach and then assigning each resource the UCAP value that results in the closer alignment between the resource’s effective capacity value and its annual CAF.
The ISO said its testing of the proposed methodology using historical data from capability year 2021/22 concluded that the new approach removed the distorted winter UCAP values that would result from the use of either approach alone and provides reasonable values for all examined resources.
The ISO also made a presentation on a consumer impact analysis it is conducting on its capacity accreditation proposal. The analysis, which will focus on the 2030 resource mix, will consider the impacts on reliability, costs, transparency and environment and new technologies.
NYISO’s Tariq Niazi said the analysis will give stakeholders an idea of the “direction [and] magnitude” of the new methodology.
The ISO plans to present the results of the analysis at the Oct. 19 ICAPWG meeting.
Query on Transmission Nodes & TCCs
In response to a stakeholder inquiry, NYISO announced it is open to considering transmission nodes as the points of injection (POI) or points of withdrawal (POW) for future transmission congestion contracts (TCC) used to hedge congestion costs.
Transmission nodes are collections of designated load buses on which individual distributed energy resources (DER) are located, mapped, and may participate together in an aggregation.
The ISO publishes a list of valid POIs/POWs before each centralized TCC auction in Attachment E of the TCC manual. For the currently ongoing auction, the ISO lists more than 300 approved locations. The ISO also prohibits the use of certain POI/POW groupings, as detailed in Attachment F of the TCC Manual.
The ISO said it will not allow transmission nodes to be a part of a TCC in its initial deployment of the DER participation model approved by FERC and that it is not required for compliance with Order 2222. (See NYISO Discusses FERC Order 2222 Compliance.)
But it said it would consider allowing nodes as the point of injection or point of withdrawal for a TCC in the future if “presented with reasonable use cases.”
“The NYISO has not yet been presented with a productive use case for TCCs at transmission nodes,” it said.
Questions and suggestions about the proposal can be directed to Kirk Dixon (kdixon@nyiso.com).
Ramp Rates for Duct-Firing Generators
The ISO proposed to change its application of generator ramp rates (MW/min) to accommodate the 45 combined-cycle gas turbines (CCGTs) equipped with duct-firing burners, which inject additional heat to their steam cycles by burning fuel directly in the exhaust duct.
The change seeks to address a concern that the units may not be able to achieve their registered emergency response rate (ERR) when ramping through the high end of their capacity where duct burners are used. The 45 CCGTs have about 840 MWs in their duct burner regions.
The ERR, which is used for scheduling of operating reserves, is a single value that must be greater than or equal to all normal response rates (NRRs).
The new proposal would create multiple ramp rates for scheduling of 10- and 30-minute spinning reserves, reflecting the lower ramp rates seen during duct firing.
The ISO said this would be consistent with its energy scheduling rules, which use multiple ramp rates.
Testing has been performed to verify that 10- and 30-minute spinning reserves are accurately scheduled across multiple ramp rates and that the concept does not harm scheduling of other energy or regulation units.
The ISO is targeting the end of October to present a market design concept. Prototyping of the 10- and 30-minute spinning reserves participation limit will begin later in the year.
Ramp Limits on ‘Internal Controllable’ Lines
The ISO provided a justification for its proposal to limit ramping on “internal controllable” transmission lines (ICL) such as Clean Path New York (CPNY).
CPNY, a 1,300-MW high-voltage direct current line that will run 175 miles from Delaware County to Queens, is expected to be the first “internal controllable line” in the New York control area.
The NYISO says HVDC lines can ramp up and down quickly with some able to reach ramp rates greater than 1,000MW per second — a far cry from the 10-20MW per minute averaged by a typical 1,000-MW generator.
Such lines can also ramp down very quickly without a change in system generation or load. Without ramping limits, the ISO says, ICL flows can shift to parallel AC lines, potentially causing voltage to drop below operating limits or flows on AC lines to exceed limits.
The ISO said the proposed ICL ramp limits will allow operators time to adjust generator reactive and real output, switch shunt capacitors or implement phase angle regulator tap changes to keep AC lines within limits.
The ISO noted that external AC transaction scheduling interfaces and controllable lines operate under interchange ramp limits to prevent voltage problems.
It said the approach to setting limits would be similar to its implementation of the 15-minute scheduling under its coordinated transaction scheduling (CTS) with PJM, “proposing to start with conservative limits and increase ramp as operators gain experience.”
The ISO plans to discuss draft interconnection manual and deliverability tariff revisions with stakeholders through November and file tariff changes with FERC by January 2023.
TEMPE, Ariz. — The Committee on Regional Electric Power Cooperation (CREPC) is attempting to play a role in Western market formation like the one performed by the Organization of PJM States Inc. (OPSI) in the East, becoming a clearinghouse of information on organized markets and an adviser and advocate for states, especially those with understaffed utility commissions.
“One of the most pressing issues in the West today is the proliferation of forums in which market participants are developing and evaluating incremental steps towards regional electricity coordination — whether through energy markets, resource adequacy sharing, transmission planning or the leap to a full regional transmission organization,” regulators and representatives from 14 Western states wrote in a letter sent to the U.S. Department of Energy in July, urging funding for the CREPC effort.
Current regional market efforts in the balkanized West include CAISO’s proposed extended day-ahead market (EDAM) for its Western Energy Imbalance Market; SPP’s planned Markets+ program, which also includes a day-ahead market; the Western Power Pool’s Western Resource Adequacy Program (WRAP), a West-side RA initiative; and the Western Market Exploratory Group, a loose coalition of utilities assessing market options.
“Each of these efforts has multiple working groups with its own set of meetings,” the letter said. “State utility regulatory commissions and energy offices often do not have the staffing levels, expertise or organizational ability to meaningfully participate in each of these market conversations — or sometimes even understand what is happening and how state interests may be implicated.
“Individual states have been working — somewhat unevenly across the region — to commit more time to regional matters, but acting now to support a collective effort to improve awareness and coordination among states will improve the outcomes of these dialogues,” it said.
The Western Interstate Energy Board (WIEB), of which CREPC is a member committee, applied for $4.1 million in DOE funding to support the initiative to allow the committee play a greater role in educating and convening Western stakeholders as they weigh market participation.
“With support, WIEB could deliver a consolidated and consistently staffed forum for states to become educated on regional cooperation development considerations, to discuss issues among one another, and to inform or respond to emerging regional designs on an opt-in basis,” the letter said.
A panel at last week’s joint meeting of CREPC and the Western Interconnection Regional Advisory Board (WIRAB) weighed the potential for creating a regional committee for the West, similar to OPSI.
“With funding support from the U.S. Department of Energy, CREPC could deliver a consolidated and consistently staffed forum for states to become educated on regional electricity coordination, to discuss issues among one another, and to inform or respond to emerging regional designs,” the agenda item for the panel said.
CREPC, established in 1982, is a joint committee of WIEB and the Western Conference of Public Service Commissioners, informally composed of state energy office officials and utility commissioners, that works to improve the efficiency of the Western grid.
David Bobzien, director of the Nevada Governor’s Office of Energy, said on the CREPC-WIRAB panel that “I consider this to be the highlight of our proceedings. … It’s been a long time coming for this discussion. There have been various conversations swirling about the West in recent months about how best to position, shape, guide [and] facilitate the conversation around markets in the West. And this is a proposal for how to answer that question.”
Another panelist, Washington Utilities and Transportation Commissioner Ann Rendahl, called the DOE funding request crucial.
“Like many agencies and state commissions and even corporations, the Washington commission has lost some staff this year,” Rendahl said. “We’re trying to replace staff at a time when it’s very difficult to get new staff. We are resource-constrained, and having the ability for this provides CREPC as an organization to more fully support states and answer some of these questions about these key market developments and aspects of markets.”
She cited the comments of FERC Commissioner Mark Christie, who spoke in a prior session and emphasized the importance of a committee like OPSI as states wade into organized markets. Christie, a longtime utility regulator in Virginia, was a founding member of OPSI in the early 2000s as PJM grew into the nation’s first RTO. The current discussion in the West about establishing a similar organization to inform and advocate for states’ interests is a “critically important topic,” Christie said.
EPA announced last week that it is nearly doubling the funds available from the Infrastructure Investment and Jobs Act for the Clean School Bus Program in 2022 to $965 million.
A first round of $500 million in May drew more than 2,000 applications from across the country. The agency said it “will move swiftly to review applications submitted and expects to issue a robust slate of awards” in the coming weeks.
The IIJA authorized $5 billion for the program over a five-year period, with the money going to provide rebates to school districts buying no- or low-carbon vehicles to replace their diesel buses. Funding for the program in 2023 will be $1 billion, EPA said.
“We’re working across all 50 states to accelerate the transition to a future where clean, zero-emissions school buses are the American standard,” EPA Administrator Michael Regan said. “America’s school districts delivered this message loud and clear: We must replace older, dirty diesel school buses.
“Together, we can reduce climate pollution, improve air quality, and reduce the risk of health impacts like asthma for as many as 25 million children who ride the bus every day,” Regan said, citing figures from the American School Bus Council.
The 2022 program guidelines prioritize applications from school districts in low-income, remote rural and tribal areas, and EPA said that “the vast majority of applicants met the priority definition … resulting in access to more funds for buses and electric vehicle infrastructure for schools in areas that need them the most.”
More than 90% of the applications were for “zero-emission electric buses,” EPA reported. Another 9% were for propane-fueled vehicles, and 1% were for compressed natural gas vehicles.
Districts chosen for awards will have to first order the buses and other infrastructure, and submit the purchase orders, to receive their rebates, EPA said.
According to a report from the World Resources Institute (WRI), 22 models of electric school buses are now available, and their efficiency and technology continue to improve. “Many manufacturers are on their second or third iteration,” all with ranges of more than 100 miles and some more than 200 miles, the report said.
The estimates on how much electric school buses reduce emissions vary. In Virginia, investor-owned utility Dominion Energy has partnered with school districts to begin transitioning their bus fleets, with 50 electric buses on the road in 15 districts. The utility estimates that each diesel bus replaced with an EV cuts emissions by 54,000 pounds per year.
Looking at lifecycle emissions — which take into account the source of electricity used to charge electric bus batteries — WRI found emissions reductions varied depending on location and the generation mix on the grid. Based on the U.S. average, lifecycle emissions for electric buses are about half those of diesel or propane-powered vehicles, but in New England, for example, the emissions for electric buses are about one third of diesel or propane.
Sen. Tom Carper (D-Del.), who chairs the Senate Environment and Public Works Committee, said, “Given the response to the availability of these [IIJA] dollars, it’s clear more funding is needed … to build on this progress so that more communities can realize the clean air and energy saving benefits of these cleaner vehicles.”
