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November 8, 2024

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4 Arizona Entities Commit to Developing SPP’s Markets+

Four Arizona electricity providers have joined seven Pacific Northwest entities to support the next phase of SPP’s Markets+ development.

SPP announced Tuesday that Arizona Electric Power Cooperative, Arizona Public Service, Salt River Project and Tucson Electric Power said in an Aug. 31 letter that they intended to work with the RTO to build a Western market that includes “both a workable governance framework and a robust market design.”

“This will be an important milestone that will enable us to collectively move forward to the next phase,” the entities said.

Last month, seven entities from the Pacific Northwest offered similar support to SPP, following a commitment from the Bonneville Power Administration. (See SPP’s Markets+ Offering Attracts 6 More Western Entities.)

“Adding the desert southwest region to the development of this market adds more value for all participants, and we very much appreciate the contributions from these entities thus far” SPP CEO Barbara Sugg said in a statement.

The four companies serve more than 20 GW of combined peak demand. The Pacific Northwest group accounts for 50 GW of combined peak demand.

SPP plans to have the Markets+ draft service offerings, based on stakeholder input, available for comment by the end of September; the final service offering is scheduled to be distributed Nov. 18. Participants will make financially binding commitments in the first quarter of 2023, at which point the market protocols and tariff language can be drafted.

Markets+ is a conceptual bundle of services that centralize day-ahead and real-time unit commitment and dispatch, provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation. It is designed for utilities that aren’t ready to pursue full RTO membership.

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CAISO Warns of Outages amid Record Heat

CAISO CEO Elliot Mainzer said the state’s grid is facing its biggest challenge yet this summer as record temperatures bake large areas of California in a prolonged heat wave this week.

“This multiday event is going to get much more intense,” Mainzer said in a call with reporters Sunday. “We’re facing energy deficits between 2,000 to 4000 MW for tomorrow, and the highest likelihood of rotating outages that we’ve seen so far.

“As a result, we are going to need significant additional consumer demand reduction during the hours of 4 to 10 p.m. and access to all of the tools that the state and the utilities have established for conditions like this in order to avoid broader interruptions of service. So, it is game on and time for continued focus.”

The National Weather Service predicted high temperatures on Monday and Tuesday in the state’s Central Valley of up to 115 degrees Fahrenheit, a level of extreme heat more often associated with areas such as Death Valley. The forecast for Sacramento called for high temperatures on Monday of 112 F and 113 F on Tuesday.

In Southern California, home to 24 million residents, Downtown Los Angeles would see temperatures of over 100 degrees on Monday and again on Thursday, the weather service said.

Even San Francisco, normally cool in the summer, was expected to top out at 88 F on Monday and 87 F on Tuesday. The weather service said parts of the heavily populated San Francisco Bay Area would be much hotter, with some cities nearing 105 degrees.

The heat will continue throughout most of this week, the weather service said.

On Monday, CAISO issued a level 1 energy emergency alert (EEA), a signal that the “real-time analysis shows all resources are in use or committed for use, and energy deficiencies are expected. Market participants are encouraged to offer supplemental energy and ancillary service bids. Consumers are encouraged to conserve energy.”

CAISO is predicting demand of 51,145 MW on Tuesday. That would beat the record of 50,270 MW from July 2006.

Though several large fires were burning in Northern and Southern California, none had impacted the transmission system.

Mainzer said the ISO was monitoring for new wildfires with the potential to derate high-voltage lines and limit imported hydroelectricity from the Pacific Northwest, an essential supply source for California during summer months.

A massive wildfire in southern Oregon severely derated the Pacific AC and DC interties during a Western heat wave last July, shutting off power from hydroelectric dams in Washington and Oregon to California.

Extreme Weather

This week’s extended period of record heat is the latest in a series of extreme weather events that have troubled California and other areas of the West in recent years. A heat dome over the usually mild, rainy Pacific Northwest in June 2021 pushed temperatures to 115 F in Portland, Ore., and 107 F in Seattle, with some inland areas hitting 118 F.

West-wide heat waves and supply constraints struck the Western grid in August and September 2020, causing CAISO to order rolling blackouts in mid-August of that year and to declare energy emergencies over Labor Day weekend. The August blackouts affected more than 2 million residents for periods ranging from roughly 30 minutes to three hours.

Since then, CAISO has interconnected several thousand megawatts of lithium-ion batteries to its grid, almost all with four-hour discharge capabilities. The batteries are intended to make up for shortfalls during hot summer evenings and have performed according to expectations so far. How the batteries will perform in more extreme conditions is being tested this week.

Until now, California’s summer has been relatively mild this year with the exception of a less severe heat wave in mid-August, when CAISO issued a “flex alert” asking customers to reduce usage.

In anticipation of hotter weather this week, California Gov. Gavin Newsom on Wednesday proclaimed a state of emergency aimed at temporarily increasing energy production and reducing demand in response to an extreme heat wave forecast to hit the state this weekend. (See Newsom Declares Emergency as Heat Stresses Calif. Grid.)

Newsom’s emergency proclamation will allow gas-fired power plants to generate additional electricity by loosening air quality requirements and restrictions on fuel use. The proclamation relaxes restrictions on the use of backup generators from 2 to 10 p.m. on days in which CAISO has declared a level 2 or 3 EEA. Ships berthed at California ports also won’t be required to use shore power during such times.

“We are anticipating this extreme heat to be of a length and duration the likes of which we haven’t experienced in some time,” Newsom said in announcing the declaration.

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Reducing GHG Emissions from Transport, Industry Seen as Key in Md.

Expanding public transportation and reducing industrial emissions are keys to Maryland meeting its climate goals, the Maryland Climate Change Commission Greenhouse Gas Mitigation Working Group was told Aug. 23.

“The best thing we can do if we want to reduce greenhouse gases is get people on transit,” Maryland Transit Administration CEO Holly Arnold said.

At present, there are more than 1 million weekly riders on the “core system,” a number Arnold said can be increased by making the system frequent, reliable and easy to use.

Last fall, MTA launched the $43 million Fast Forward program, which seeks to improve service reliability, reduce travel times, and increase safety and access. The program includes more dedicated bus lanes, real-time bus tracking and — starting later this year — real-time rail tracking and information on bus crowding.

Most significantly, MTA is also transitioning to zero-emission buses, committing not to buy any more diesel buses after fiscal 2023 and seeking to make 50% of the fleet zero-emission by 2030. The regional transit plan’s goal is a 95% zero-emission fleet by 2045, but “it will be a lot of work to accomplish this transition,” Arnold said.

She cited concerns that battery electric buses may not be appropriate for all locations, saying, “We have to make sure it doesn’t run out of charge in the middle of a route.”

In a pilot project, MTA will get seven battery electric buses and five overhead chargers early next year. The agency is working with Baltimore Gas and Electric on infrastructure. MTA has a six-year $4 billion capital budget for this and other projects, Arnold said.

Cement Leading Source of Industrial Emissions

The Mitigation Working Group also heard a presentation from the University of Maryland School of Public Policy’s Center for Global Sustainability (CGS), which is conducting a study due to the governor Oct. 1 on the economic impact of regulating greenhouse gas emissions from the manufacturing sector. The study was required by the 2016 amendments to the state Greenhouse Gas Reduction Act.

The sector presents a unique challenge for the state’s emission-reduction goals, even though it is not a major component of emissions, said Ryna Yiyun Cui, an assistant research professor at CGS.

Following the 2011 closure of RG Steel’s Sparrows Point plant, the state’s biggest industrial emitter of greenhouse gas is the Lehigh Hanson cement plant in Union Bridge, followed by Holcim, a building materials manufacturer in Hagerstown, according to Kathleen Kennedy, a postdoctoral associate at CGS.

CGS’ Jared Williams said the greatest potential for reducing greenhouse gas emissions in this subsector is in the manufacture and mixing of cement, specifically, the production of clinker, the primary source of process emissions generated in cement manufacturing.

“Substituting clinker with decarbonated materials reduces process emissions from cement manufacturing,” he said. “Replacement of ordinary portland cement with portland limestone cement [PLC] reduces emissions and is also less costly.” Limestone cement may dominate the cement market as early as next year, he said.

Lehigh Hanson announced in July it will transition to limestone cement at the Union Bridge plant by January 2023, which is expected to cut its emissions by 18%. Holcim plans to switch to PLC after the installation of new equipment, with expected reductions of 11%.

Further reductions will come from Lehigh’s plan to switch from coal to natural gas by 2028. Hydrogen is a potential long-term alternative fuel for cement manufacturers but requires further research.

Because process emissions from cement manufacturing are unavoidable, carbon capture, utilization and storage may be needed to address the final 50% of emissions to get to net zero.

Industrial greenhouse gas emissions in Maryland were reduced by more than 30% from 2006 to 2020, Cui said. The main reduction has been in the electricity and road transport sectors, although they remain the major emitters in the state. Industrial processes using fossil fuels constituted a little less than 10% of the state’s emissions in 2020, a slight decline since 2006.

Kennedy added that the manufacturing sector’s contribution to state GDP has stayed relatively constant around $20 billion, or 6 to 7% of the total, over the past few years. Manufacturing employment — about 120,000, or 3 to 4% of the state’s total jobs — has also stayed fairly constant recently. The economically significant computer and electronics sector is responsible for a low percentage of energy consumption. On the other hand, food, which is responsible for a relatively large proportion of energy consumption, is not a particularly high emitter because it uses mainly natural gas and electricity, as opposed to heavy industries that still use coal.

The 30% decline in the manufacturing subsector’s emissions was driven primarily by reduced fuel combustion after RG Steel shut down, Kennedy said. But “process and product use emissions” have gone up since 2017; by 2020, these constituted 69% of total industrial emissions, although they have declined in absolute terms by about 25% since 2006, she said. Emissions are still growing in cement, up 21% since 2006, and ozone-depleting substances or substitutes are also up 42%. Union Bridge’s emissions have been growing because of increased production.

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CAISO Stakeholders Weigh EDAM Proposal

CAISO kicked off a series of stakeholder meetings last week on its revised straw proposal to add a day-ahead market to the real-time Western Energy Imbalance Market (WEIM), a major expansion push for the ISO in the West.

Potential participants in the extended day-ahead market (EDAM) were able to ask questions of CAISO planners and offer their thoughts on the plan’s specifics, including a proposed resource sufficiency test and resource participation, during the Aug. 29 meeting.

Carrie Bentley, an energy consultant representing the Western Power Trading Forum, asked why CAISO’s proposal would require that all resources in a participating balancing authority area (BAA) take part in EDAM when that’s currently not the case in the WEIM.

“I was hoping you could provide more color on why the CAISO was removing the option for resources to be nonparticipating?” Bentley said. “It was my understanding that in WEIM, the amount of nonparticipating resources [as a percentage of capacity] is pretty high. So perhaps if you could tell me … why you’re removing that option? And then whether you’re going to then remove it from WEIM as well? It just seems to remove a lot of optionality.”

CAISO Executive Principal George Angelidis said the “reason why we eliminated the option for the nonparticipating resource concept that we’re using in the Western Energy Imbalance Market is that we don’t see the value for it, in the sense that it doesn’t give you anything different than a normal resource that participates in the market with a self-schedule and not submitting bids. The submission of bids is voluntary in EDAM, with the exception, of course, of resource adequacy, [so] we just didn’t see any difference between participating and nonparticipating resources.”

Bentley said she understood but still saw possible benefits to having the option of nonparticipating resources.

Resource Sufficiency

On the topic of resource sufficiency, Powerex Director of Power Jeff Spires said CAISO’s proposal to use “e-tags” to track the fulfillment of firm energy contracts in EDAM was essential but that a second proposal to allow participants to backfill capacity at the last minute undermined the process.

The EDAM revised straw proposal introduced the “tagging mechanism,” or e-tag, a means of electronically monitoring and recording energy transactions for firm energy contracts. The proposal requires “all non-source-specific forward supply contracts [to] be tagged within three hours following publication of the day-ahead market results.”

“This will increase confidence that this non-source-specific forward supply will be delivered in real time because submitting a tag requires resource and transmission identification.” (See CAISO Updates EDAM Straw Proposal.)

Spires said, “We all know by this point … that resource sufficiency is one of the fundamental elements of the EDAM and that really is one of the first steps that we need to get right before the remaining market design elements can fit together and work. You know, it all kind of starts with an assumption that there’s enough supply across the footprint and that everyone’s bringing their fair share.”

“That requires ensuring that the [resource sufficiency] test is representative of both the supply and the obligations of each BA and in the context of imports,” he said. “In our view, that means that imports that are being used to meet the resource efficiency evaluation need to be real; they need to be deliverable to the BA that’s counting on them. And a day-ahead e-tag is a critical element to be able to demonstrate that the import is supported by a resource and that there’s transmission to deliver it.”

CAISO, however, is also proposing that “non-tagged schedules will be required to submit e-tags, or otherwise cure shortfall, by the start of the STUC [short-term unit commitment] horizon for the hour in which the failure occurred,” a slide in the ISO’s presentation said.

The revised straw proposal says that when an EDAM participant is short on supply in the day-ahead time frame, “it can backfill the deficiency with supply” in the short-term horizon “ending in the hour” of the shortage.

That part is a challenge, Spires said, “because it essentially renders that day-ahead e-tag requirements as optional. And what it really leads to is enabling an entity to point to an import that isn’t supported by identifiable supply or transmission and essentially says that ‘that’s OK,’ as long as that participant is able to successfully find supply or transmission or both in real time. And that’s very problematic in our view. It erodes confidence in the test itself because it effectively says that an entity can pass [the EDAM’s resource sufficiency test] even though they are going into real time short of resources and or transmission.”

In reply, CAISO Market Design Sector Manager Danny Johnson said, “I think we do understand your position and Powerex’s position on this. I think what we’re trying to explore here is, ‘Is there a model that deviates from [the day-ahead e-tag] that also provides confidence to all of the interested BAA partners in this?’ And that’s what we’re exploring in this proposal. And I do think there are some teeth to this. We will be reporting out if this doesn’t occur regularly. If an EDAM BAA does eventually fail to tag by [the start of the hour in the STUC horizon for which the failure occurred], they would get kicked out of [a pooled resource sufficiency evaluation], and I think we even have provisions that the export transfers into that EDAM BAA would get a lower priority if it came to manual curtailments if the market was unable to solve. So, I do think this has some teeth” and provides confidence level in the EDAM’s resource sufficiency evaluation.

The EDAM stakeholder meetings resume this week with sessions on Wednesday and Thursday, including an in-person option in downtown Sacramento.

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Stakeholders Challenge PJM in Capacity Accreditation Talks

A long-simmering dispute over PJM’s capacity accreditation of renewable resources is threatening to boil over, with some stakeholders calling for FERC intervention.

At issue is PJM’s grant of capacity rights to wind and solar resources at levels that some stakeholders say have not been proven deliverable under peak conditions. The stakeholders say the practice is a reliability risk and is suppressing capacity prices. Fixing the problem could require transmission upgrades costing load up to $2 billion or more.

At a special Planning Committee meeting on capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources Aug. 23, stakeholders accused PJM of improperly attempting to engineer a solution in favor of lower capacity prices, while RTO officials insisted they were only trying to offer “transparency” on the impact of potential rule changes.

Economist Paul Sotkiewicz, of E-Cubed Associates, cited PJM’s presentation at the meeting that summarized the solution proposals that had resulted from 18 prior meetings. “Some packages can delay availability of higher accreditation, which causes increased capacity costs borne by load,” PJM said.

“PJM taking a market position for lower capacity costs is inappropriate at best. At worst it’s begging a referral to the FERC [Enforcement] Hotline,” said Sotkiewicz, who formerly served as PJM’s chief economist.

“This is not a PJM position,” PJM attorney Pauline Foley responded. “It’s simply a statement of fact.”

Vice President of Planning Ken Seiler said the RTO is “squeezed.”

“We’re trying to be as transparent as possible about the potential impact” of proposed changes, he said. “We get accused of not being transparent, and we get accused of taking a position.

“We don’t care what capacity prices are,” he insisted. “We care about the reliability of the system. We’re not taking a position on capacity prices at all.”

Seiler opened the meeting — the first by the special committee in two months — by saying the RTO had decided to “recalibrate and reset where we are” in response to stakeholder feedback in prior meetings and is not currently endorsing any package. “We as an organization are not married to any one particular package,” he said.

Marji Philips of LS Power said stakeholders are frustrated that PJM has insisted there is no over-accreditation problem even as it proposes spending billions to fix it. The RTO’s position “reminds me of George Orwell,” she said. “I’m trying to be respectful, but that was the weirdest explanation and disinformation I’ve heard in a while.”

But Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), said PJM had done nothing wrong.

“It’s perfectly appropriate in a cost-benefit analysis for PJM to reflect” the impact on capacity prices, he said.

Sotkiewicz told Seiler that stakeholders were reacting to PJM staff taking “very definitive position [at a] very ugly meeting” June 24. “So what I think you’re hearing is that blowback,” he said.

That blowback has included at least one referral to the FERC hotline, according to a stakeholder who asked not to be identified. The stakeholder said two other stakeholders have also contacted the commission about what they see as tariff violations.

Problem Statement

PJM initiated the special meetings in early 2021 with a problem statement calling for discussions on: “the appropriate amount of capacity interconnection rights required for existing and planned generation capacity resources; the interrelationship between CIRs and the amount of capacity offered into the capacity market; the role CIRs should play in resource adequacy considerations; and CIR retention policies that strike a proper balance between continuing to support the reliable output of the resource while not resulting in unnecessary baseline upgrades.”

The initiative was proposed while PJM awaited FERC’s response to its proposed ELCC construct, which the commission approved on July 30, 2021 (ER21-2043). (See FERC Accepts PJM ELCC Tariff Revisions.) PJM uses probabilistic modeling to evaluate the contribution that ELCC resources — those such as wind and solar that are unable to maintain a stated output continuously without interruption — make to meeting PJM’s loss-of-load expectation (LOLE) standard of one day in 10 years.

Letters to Board

Economist Roy Shanker, who has represented LS Power during the committee sessions, says PJM has knowingly violated its tariff, the Reliability Assurance Agreement (RAA) and its interconnection service agreements (ISAs) by allowing renewables to sell capacity at levels above those for which they’ve qualified as deliverable.

The ISAs state that any output above an ELCC resource’s CIRs — determined by the amount that can be delivered during peak conditions — is considered an energy resource and not eligible as capacity, Shanker and others say.

But they say PJM has knowingly allowed energy output to be sold as capacity by accrediting based on units’ maximum output.

In February 2022, after a dozen meetings of the special PC committee, the PJM Power Providers Group (P3) sent a letter to the Board of Managers alleging the RTO was “knowingly allowing resources that cannot deliver all of their accredited capacity to acquire a capacity obligation greater than what is deliverable” at peak times.

P3 President Glen Thomas said the RTO could fix the problem by enforcing the RAA requirements with no need for a FERC filing. Instead, Thomas said, PJM proposed in the stakeholder process building transmission upgrades to increase the deliverability of the resources and to socialize the costs of the improvements.

‘Extreme and Unjustified Intervention’

Renewable supporters, including the Solar Energy Industries Association and American Clean Power Association, responded that P3 was seeking an “extreme and unjustified intervention in the market” that would “circumvent the stakeholder process” based on “unproven assertions about the deliverability impact of changes in PJM’s process that were made long after those resources were interconnected.”

The groups countered that the board should take action “to address the profound disparate treatment in which some resources in the capacity market are now accredited recognizing fuel and weather-related correlated outage risk (ELCC resources), and the remainder (thermal resources) are not.”

“To the extent that there is discrepancy between the deliverability determined through CIRs at the time resources interconnected and the ELCC capacity accreditation methodology that was adopted later, we note both that (1) this discrepancy did not take place due to any action taken by existing resources, and (2) is instead the result of adopting ELCC only for some of PJM’s generation fleet,” they said.

While PJM applies ELCC to wind, solar and storage, they said, thermal resources are given capacity rights up to their nameplate capacity — reduced only by the unit’s equivalent forced outage rate (EFORd).

“This effectively subjects wind, solar, and storage resources to an ever-shifting capacity value based upon fleetwide entry and exit decisions,” they said.

“PJM’s current approach treats 93% of PJM’s fleet — thermal generators — as near perfect capacity resources with no correlated outage risk. … As recent events such as Winter Storm Uri have demonstrated, this implicit assumption is demonstrably false.”

At the committee’s Feb. 23 meeting, PJM insisted its implementation of ELCC complies with the RAA, contending that only 5 MW of renewable generation with signed ISAs that are not yet in service may not be deliverable under proposed, higher deliverability standards. The RTO said it would cost $7 million in transmission upgrades in the 2026 Regional Transmission Expansion Plan to increase CIRs for those resources. The board echoed that position in its March 4 response to P3 and the environmental groups.

Upcoming Meetings, Nonbinding Poll

PJM’s Brian Chmielewski said stakeholders will be asked in a nonbinding poll to choose a solution proposal after special PC meetings scheduled for Tuesday and Sept. 23. At the Tuesday meeting, PJM will present a comparison of the six current proposals, whose cost implications depend on how they are implemented in regards to the transition plan the RTO  included in its June tariff filing proposing to change its interconnection process from a serial “first-come, first-served” approach to a clustered “first-ready, first-served” cycle (ER22-2110). (See FERC Issues Deficiency Letter on PJM Queue Overhaul.)

PJM says two alternative proposals before stakeholders that would not introduce the higher CIRs for wind and solar ISA holders until transition cycle 2 would result in $2 billion in baseline upgrades that would be allocated to load.

Four other proposals would result in about $700 million in costs to load by introducing the higher CIRs for wind and solar ISA holders in cycle 1 instead of cycle 2. The $1.3 billion difference would be paid by cycle 1 resources as increased network upgrade requirements, PJM said.

Shanker and others say PJM is pushing to allow existing wind and solar resources their CIRs at no cost by giving away 7,300 MW of existing “headroom” and allowing them to jump ahead of resources already in the interconnection queue. Shanker said PJM’s $2 billion estimate “is clearly a lower bound.”

The Independent Market Monitor said in February that PJM has given wind and solar resources an installed capacity (ICAP) of 3,393.8 MW when they should only claim 2,260.3 MW, based on CIR levels — an excess of 1,133 MW. Based on the Monitor’s estimate, Shanker said he believes the practice suppressed prices in the 2022/23 Base Residual Auction by $200 million.

PJM estimated a slightly larger impact in June, saying that capping wind and solar at their current CIR level in the ELCC studies would reduce their capacity by about 1,300 MW. A sensitivity simulation found that removing the 1,300 MW would have cost load $230 million for the 2022/23 BRA, PJM said.

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PJM Appoints Vickie VanZandt to Board of Managers

PJM has appointed Vickie VanZandt, the owner of a energy consulting firm, to its Board of Managers, according to a Friday statement from the RTO.

The president of VanZandt Electric Transmission Consulting, VanZandt will take the place of Sarah Rogers, who resigned from the board Sept. 2 after more than 10 years of service. VanZandt will begin her term Oct. 1 and will serve until at least May 2023, when she will stand for election at the RTO’s Annual Meeting.

Rogers, who had been re-elected in 2021, announced her intent to retire in May. PJM’s Operating Agreement stipulates that the board itself fills any vacancies until the next Annual Meeting, where members will vote on the appointment. PJM’s Nominating Committee recommended VanZandt for the appointment.

In addition to her consulting work, VanZandt currently serves on the ISO-NE Board of Directors, where she chairs the System Planning and Reliability Committee. She is serving her third consecutive three-year term on that board, the maximum allowed, and it will end the same day she begins her term at PJM. (See LaFleur Elected to ISO-NE Board.) Her departure will bring the ISO-NE board back down to its normal 10-person membership, after having 11 for one year. (See ISO-NE Elects Melvin Williams Jr. to Board.)

VanZandt has previously worked at the Bonneville Power Administration as a senior vice president and chief engineer of transmission services, overseeing transmission planning, construction, operation and management. She then worked at WECC as synchrophasor program manager.

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FERC OKs CAISO Interconnection Updates

FERC last week approved a dozen CAISO tariff amendments meant to streamline the ISO’s generator interconnection process, deal more swiftly with its large interconnection queue and help California meet its grid reliability challenges. (ER22-2018).

The changes were the result of the first phase of a two-part stakeholder initiative that CAISO fast-tracked starting last year. The second phase is underway with a final proposal due Sept. 13.

FERC found that the Phase 1 revisions will “facilitate management of CAISO’s interconnection queue, clarify the tariff, and establish a just and reasonable process for CAISO to study emergency interconnection requests on an expedited basis.”

The 12 amendments included a proposal to align the ISO’s transmission plan deliverability allocation process with procurement by consolidating the current seven interconnection customer deliverability allocation groups into four, making it easier for CAISO to track the process and providing clearer criteria for developers and off-takers.

“Additionally, the new groups are reordered to emphasize success in the bilateral capacity markets and de-emphasize a project’s queue status and history,” FERC said in its unanimous Aug. 31 order.

The amendments also would allow interconnection customers to downsize their interconnection requests.

“CAISO’s proposed revisions to the transmission plan deliverability allocation process and to the downsizing rules simplify CAISO’s administration of the interconnection queue and the process through which interconnection customers may request to downsize their interconnection requests, as well as help to reduce unused deliverability,” FERC said.

Another change affects CAISO’s requirement that customers show they have “site exclusivity” through options, leases, or purchases on private land or permits for public lands. Customers can submit deposits in lieu of initially demonstrating site exclusivity.

CAISO proposed requiring projects show that they have site exclusivity earlier and increasing the “in lieu deposits” from $100,000 for small generators of 20 MW or less and $250,000 for large generators of more than 20 MW to $250,000 for small generators and $500,000 for large generators, with half the deposits nonrefundable “should the customer withdraw before demonstrating site exclusivity.”

FERC said the site-exclusivity provisions will “improve the likelihood that commercially feasible interconnection requests can move forward in the queue without encountering delays due to the withdrawal of interconnection requests that have not demonstrated site exclusivity and are thus less likely to reach commercial operation.”

The 10 other categories of tariff amendments dealt with matters such as enabling interconnection studies of new generation under last year’s emergency declaration on grid reliability by Gov. Gavin Newsom and reducing CAISO’s downsizing rules and procedures to help interconnection customers downsize more efficiently.

FERC allowed the changes to take effect Sept. 1, per CAISO’s request.

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CARB: ACC II PHEV Provision Designed to Drive ZEV Adoption

While California’s recently adopted Advanced Clean Cars II regulations are often described as banning the sale of gasoline-powered cars starting in 2035, the rule won’t eliminate internal combustion engines in new passenger vehicles.

The regulation, adopted by the California Air Resources Board last month, allows up to 20% of a car manufacturer’s annual ZEV requirement to be met with plug-in hybrid electric vehicles (PHEVs).

When asked about the rationale for allowing continued sales of PHEVs, which can run on gas as well as battery power, CARB spokesman Dave Clegern said the agency has estimated that about three-quarters of trips in plug-in hybrids will be electric.

“These are essentially electric cars with conventional motors for special circumstances,” Clegern told NetZero Insider.

To count toward the ACC II ZEV requirement, PHEVs must have a minimum battery range of 43 miles through model year 2028 and 70 miles thereafter. Clegern said the vehicles must also meet stringent emission standards and have a 150,000-mile extended warranty on emission controls.

Automakers will have to meet at least 80% of their ZEV requirement with pure zero-emission vehicles such as battery electric or fuel cell electric vehicles, Clegern noted.

Kathy Harris, a clean vehicles and fuels advocate at the National Resources Defense Council (NRCD), acknowledged that plug-in hybrids emit tailpipe pollution when they’re not in electric mode.

“But these vehicles may help drivers in the transition to a fully electric vehicle, in particular for demanding duty cycles such as towing,” Harris told NetZero Insider.

System of ZEV Allowances

The California Air Resources Board on Aug. 25 voted to adopt the Advanced Clean Cars II (ACC II) regulations, which are a follow-up to the Advanced Clean Cars I rules in effect now through model year 2025. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

Like Advanced Clean Cars I, ACC II will require automakers to provide for sale an increasing percentage of zero-emission vehicles in California each year. ACC II starts with a 35% ZEV requirement in model year 2026, increasing to 100% in 2035.

Advanced Clean Cars I uses a system of ZEV credits that is based on the electric range of a vehicle and other factors. Some ZEV models receive more than one credit per vehicle. In contrast, ACC II will use ZEV “values” rather than credits. One zero-emission vehicle will equal one value.

ACC II includes a variety of ZEV allowances, including early compliance values, interstate transfers and environmental justice values, to help automakers meet ZEV requirements.

Harris from NRDC said the ZEV allowances will be especially important to automakers in states where ZEV sales are not as strong as in California.

“However, it is important that regulations result in real zero-emission vehicles — and their benefits — on the road in the states that adopt the rules,” Harris said.

Limits on the use of the allowances, and their phase-out by 2031 at the latest, will help ensure that’s the case, she said.

Credit Conversion

Manufacturers will be able to convert excess ZEV and plug-in hybrid credits earned under ACC I to ACC II values by dividing the number of credits by 2.1. The converted credits may be used to meet up to 15% of an automaker’s ZEV requirement in model years 2026 through 2030. There’s also a cumulative allowance option for automakers to use the converted credits.

Early compliance allowances are another tool manufacturers may use to meet their ZEV quotas. The values may be earned in model years 2024 and 2025 if more than 20% of the light-duty vehicles a manufacturer provides for sale are ZEVs or plug-in hybrids.

Early compliance values may be used to meet up to 15% of an automaker’s ZEV quota in model years 2026 through 2028. The early compliance values cannot be transferred to other states.

In an arrangement known as “pooling,” an automaker may transfer excess ZEV values earned in one state that has adopted ACC II to use toward ZEV requirements in another state.

The values can only be transferred when the ZEV requirement has been exceeded in one state, and only used to fill a shortfall in another state. Pooled values can be used to meet up to 25% of a state’s ZEV requirement in 2026, decreasing by 5% each year through 2030. Pooling won’t be allowed after 2030.

EJ Values Introduced

Environmental justice values are another ZEV allowance available to automakers. On top of the value earned for providing the ZEV itself, additional value will be awarded when the manufacturer takes steps to help place the vehicles in disadvantaged communities.

One example is providing the vehicle at a discount to a community-based clean mobility program, such as a car share program. In that case, the EJ value is 0.5 for a ZEV and 0.4 for a plug-in hybrid. The discount must be at least 25% off the manufacturer’s suggested retail price (MSRP).

EJ values of up to 0.25 may be earned when a ZEV or plug-in hybrid initially leased in California is sold at the end of lease to a California dealership participating in a financial assistance program. The ZEV or plug-in hybrid must have had an MSRP of $40,000 or less when it was new.

And for model years 2026 through 2028, automakers may earn an EJ value of 0.1 for each ZEV or plug-in hybrid provided for sale with an MSRP of $20,275 or less for passenger cars and $26,670 or less for light-duty trucks.

The EJ values may be used to meet up to 5% of a manufacturer’s ZEV quota. EJ values can’t be used after model year 2031, and they can’t be transferred to another state.

In other provisions of ACC II, excess ZEV, plug-in hybrid and environmental justice values may be banked for use in future model years. But excess ZEV and plug-in hybrid values can only be used for the four model years after the year they were earned.

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Storage Underestimated in NYISO ‘Outlook,’ MMU Says

NYISO’s new long-term planning forecast is a major improvement but underestimates the role of merchant storage and increases the apparent need for transmission, according to the ISO’s Market Monitoring Unit (MMU).

Potomac Economics’ Joseph Coscia presented the MMU’s review of the System & Resource Outlook to the ISO’s Management Committee on Wednesday, before the committee recommended approval of the report to the Board of Directors. The ISO’s first 20-year economic planning forecast, the outlook predicts a need for more than 95 GW of new zero-emission resources by 2040, 20 GW within the next seven years, to meet New York’s goals under the Climate Leadership and Community Protection Act (CLCPA). (See NYISO 20-Year Forecast Highlights Generation, Tx Hurdles to Climate Goals.)

The MMU said the outlook incorporates “major enhancements” to previous economic planning studies and is “the most sophisticated forecast to date of how state policies will affect the NYISO system.” But the amount of generation that the outlook says is needed could be reduced with wider deployment of storage to reduce renewables’ curtailment, Coscia said in an interview.

While the outlook helps identify where new transmission could reduce congestion and make renewable energy more deliverable, the MMU said its analysis “sheds light on how NYISO’s wholesale markets can facilitate more efficient clean energy investments that reduce the need for regulated transmission investments.”

New Terms

Potomac’s analysis introduced three terms that it said would allow planners to compare the relative costs of renewable and storage resources and interconnection locations.

The “renewable deliverability ratio” is the share of an incremental resource’s output that would not cause curtailment of other resources. A wind project that can produce 3,200 MWh annually and loses 300 MWh to curtailments and causes other renewables to be curtailed by 500 MWh would have a ratio of 75% (2,400/3,200 MWh).

Closely related is the “renewable deliverability impact,” the megawatt-hours of renewable energy that an incremental megawatt of generation, storage or transmission capacity makes deliverable to load.

Those metrics affect the “implied net REC cost,” the average renewable energy credit (REC) payment a project would need to be economic, expressed in dollars per megawatt-hour of renewable energy that it can deliver without increasing curtailments of other resources.

Cannibalization

New renewables can be more costly than they appear because a resource receiving higher REC payments may run inefficiently and contribute to more congestion while other less costly resources are curtailed because they are receiving lower REC payments, Potomac said.

Owners of existing units who suffer this “cannibalization” — losing RECs because of increased curtailments caused by the new unit — will attempt to pass the costs to end users through higher REC prices.

As a result, Potomac said, policymakers should seek uniform pricing of clean energy to avoid undermining market efficiency.

“The value of storage and transmission projects may be distorted if the renewable energy curtailments they reduce are not valued consistently,” it said.

Incremental Storage

While new renewables can undermine existing resources by adding to congestion, storage reduces curtailments and lowers the amount of renewable capacity needed to meet New York’s goals, Potomac said. It said the outlook’s Scenario 2 case, which envisions high renewable penetration, underestimates storage with its assumption of 4.7 GW.

“When storage resources charge to relieve curtailment of renewable resources that earn REC payments, the value of the REC is passed through to the storage owner via negative prices,” the MMU said.

The implied net REC costs for land-based wind, offshore wind and solar are likely to increase between 2030 and 2035. But Potomac says net prices for four-hour storage will drop, because of its ability to increase renewables’ deliverability and take advantage of higher price volatility.

Additional storage beyond the 4.7 GW would be economic based on market prices at locations where frequent curtailments and negative pricing provide substantial revenues for batteries that charge to reduce the curtailments, Potomac said.

Implied net REC costs (Potomac Economics) Content.jpgImplied net REC costs for land-based wind (LBW), offshore wind (OSW) and solar (PV) are likely to increase between 2030 and 2035 while four-hour storage will drop, making it “very cost-effective,” according to NYISO’s Market Monitoring Unit. The MMU defines implied net REC costs as the net cost of incremental renewable energy deliveries from an investment in generation, storage, or transmission. | Potomac Economics

 

The MMU identified 32 such locations in 2030, projecting storage’s median cost there at $24/MWh. With the median cost dropping to a projected $6/MWh by 2035, that would rise to 107 locations — more than half of the total nodes modeled by the ISO.

“This suggests that the amount of storage in the outlook is inefficiently low in 2035,” the MMU said.

Storage is most economic in upstate areas with low renewable deliverability ratios and least economic in New York City (Zone J) where offshore wind is expected to have higher deliverability ratios.

The outlook models assumed the location of new renewables based on projects in the current interconnection queue and did not fully consider whether the resulting mix of locations is economic or whether a different mix would be more attractive to developers, Potomac said.

“This approach is reasonable given the NYISO’s limited information but runs the risk of relying too heavily on the current queue,” it said, noting that the outlook’s capacity expansion model does not capture congestion and prices at the nodal level.

Recommendations for Future Outlook Modeling

Potomac recommended that NYISO perform an optimized production cost model sensitivity case with new renewables relocated to more deliverable sites and add options for two-, six- and eight-hour storage in its capacity expansion model, which is currently limited to four-hour storage.

“Longer-duration storage resources have higher capacity value and might cost-effectively provide peaking capacity in the long term while reducing curtailment of renewables,” the MMU said.

The low renewable deliverability ratios at many locations in 2035 suggest that changing the location of renewable resources would reduce curtailments and increase deliverability, Potomac said.

It cited the study’s projection that wind generation at the 115-kV Bennett line in Zone C will increase from 239 MW in 2030, with a 56% deliverability ratio, to 771 MW by 2035, with deliverability falling to 10%. “Many other locations across the upstate region have much better renewable deliverability ratios, indicating that it might be more efficient for some of the 771 MW of wind capacity modeled at Bennett 115 kV to be built elsewhere,” Potomac said.

It acknowledged that factors such as land availability, permitting considerations and site-specific costs can cause developers to pursue projects at congested locations and that locations with high deliverability may be inaccessible or more costly.

The MMU also said the ISO’s transmission planners should estimate the implied net REC cost of regulated transmission projects and compare them to alternatives including merchant battery storage and renewables.

Planners should “exercise caution when evaluating benefits of transmission projects whose value is strongly linked to uncertain long-term generator siting decisions,” it said. Transmission projects designed to clear constraints are more likely to be economic if selected in areas where renewables have a high probability of entering service or “superior land availability, resource potential or special cost advantages.”

“Ultimately, planners should promote regulated transmission investment only when it is cost effective, since inefficient transmission investment tends to crowd out more cost-effective investments in generation and storage,” Potomac said.

The MMU also raised questions about the outlook’s modeling assumptions, saying it “relied on forecasts derived from currently known assumptions, which are unlikely to accurately predict how economics and policy will shape the long-term NYISO resource mix.”

For example, it noted that the outlook’s Scenario 2 case forecast no additional utility-scale solar until after 2030. But as the ISO was completing the outlook, the New York State Energy Research and Development Authority announced in June it had contracted for 2.4 GW in additional solar. “This suggests either that a large number of projects with state REC awards are not economic and will not enter service, or that the outlook underestimated future solar development compared to wind,” Potomac said.

Potomac’s Coscia praised NYISO’s efforts, telling the Management Committee that the outlook includes “a lot of really key improvements.” But he said planners should press for more improvements. “For studies of this magnitude, it’s always an iterative process from one to the next,” he said.

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Virginia RFP for LMI Solar Pilot Fails to Draw Bidders

The Virginia Clean Energy Advisory Board (CEAB) is reconsidering how to launch a solar pilot program for low-to-moderate-income (LMI) residents of Wise County after a request for proposals (RFP) for financing and installation contractors closed without any submissions.

Taylor Brown delivered the bad news to his colleagues on the board at its Aug. 22 meeting. “There were no respondents to the RFP, but there was a lot of actionable comment to issue an improved one,” said Brown, who is the chief technical officer at Charlottesville, Va.-based Sun Tribe Solar, a solar engineering, procurement and construction firm.

Solar companies gave three main reasons for not wanting to participate, he said, though different firms weighed the factors differently. First, only a small number of contractors can install the necessary equipment. Second is uncertainty over how residential solar leases are regulated in Virginia, a matter on which the state’s Office of the Attorney General is expected to issue an opinion by October. Third, Brown said, is the questionable viability of Virginia’s residential solar leasing market beyond the two-year term of the funding in the RFP. Solar companies say they want to offer their product to everybody, not just designated LMI residents, he said.

Wise County in southwest Virginia was one of five sites proposed for the pilot project by the Clean Energy States Alliance, which received a grant to assist the state and CEAB in developing the pilot.

Carrie Hearne, associate director of energy equity programs at Virginia Energy, said that there are three or four companies that could participate in a revised RFP. “Several other companies were familiar with it, but they didn’t have the bandwidth, or the incentives didn’t match their business model,” she said. “Every company had different considerations.”

‘Very Limited Amount’ of LMI Solar Power in Virginia

“There is a very limited amount of LMI solar that is currently operational in Virginia,” Brown said.

Virginia has nearly 500,000 LMI single family owner-occupied households potentially suitable for solar production with a potential capacity of 3,111 MW, according to the RFP. Wise County has 3,067 LMI owner-occupied households with potential solar capacity of 23 MW.

The Virginia Clean Economy Act of 2020, which took effect last year, requires Dominion Energy (NYSE:D) to obtain 14% of its power from renewables in 2021, rising to 41% by 2030. The law includes a carveout requiring at least 1% of the renewables come from solar resources of less than 1 MW, a quarter of that from LMI projects, Brown said.

The law requires Dominion to pay $75/MWh for any shortfalls on the 1% carveout, “a decent amount of added revenue into a third-party financier’s model,” but one that was apparently not “properly factored in” by companies that were considering participating in the failed RFP, Brown said. Potential bidders in the next RFP would benefit from more clarity on this score, he said.

“We’re trying to sell a niche product for which there is no market anywhere in Virginia,” Brown said. “So we need to have companies that are going to finance the back end. That’s as difficult as the contractor end, from what we’re hearing.”

Austin Counts of Virginia Energy expressed optimism, saying the residential solar market is still growing. “We have talked with at least four different installers [in the Wise County area], and we plan on reaching out to several more — there are about 15 on our list. We will hold meetings through mid-September.”

Board member John Warren, director at Virginia Energy, suggested rethinking “how we are doing this process for this pilot project.” He proposed setting a “unit cost” for Wise County households, so that “we can tell installers, that is what they will get paid.”

The full board agreed that its Program Development Committee will work on the RFP revision and present a new draft at the next board meeting in October.