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.
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.
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.
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 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.
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.
The California legislature’s recently completed session saw a handful of bills introduced to promote transmission development, but only one of the measures escaped unscathed while the rest died or were watered down.
The bills mainly aimed to move more energy from renewable resources to help the state meet its goal of relying on 100% clean energy by 2045, as required by 2018’s Senate Bill 100.
The only significant bill to emerge intact was SB 887 by Sen. Josh Becker (D).
The bill would direct CAISO, the California Public Utilities Commission and the state Energy Commission to expand their generation and transmission planning horizons from the current 10 years to “at least 15 years … to ensure adequate lead time for [CAISO] to analyze and approve transmission development and for the permitting and construction of the approved facilities.”
CAISO already performs a 20-year transmission outlook, but it is a long-term conceptual plan of grid needs, including out-of-state projects, intended to complement but not replace the ISO’s 10-year transmission planning process, which concerns only in-state projects.
Becker’s bill would instruct CAISO to identify “the highest priority transmission facilities that are needed to allow for reduced reliance on [fossil fuel] resources in transmission-constrained urban areas by delivering renewable energy resources or zero-carbon resources that are expected to be developed by 2035 into those areas.”
It cleared the Assembly on Aug. 29 and goes to Gov. Gavin Newsom for his signature or veto by Sept. 30.
One bill, which had been considered a major transmission measure in the 2021/22 legislative session, was stripped of its more substantive provisions and became a new law requiring utilities to file annual reports with the CPUC.
SB 1174, by Sen. Robert Hertzberg (D), a former Assembly speaker, would have directed the CPUC to work with CAISO, the Energy Commission and the state Air Resources Board to “identify all interconnection or transmission projects necessary to achieve” the goals of SB 100 and to prioritize approval of the projects.
One of those needs could be a 200-mile undersea cable linking offshore wind farms in far northern California to San Francisco and other population centers. Such large-scale projects mean that speeding transmission “may be one of the most important steps we can take to connect bold planning with common-sense policy,” Hertzberg said in a statement earlier this year.
The measure that cleared the legislature on Aug. 30, which Newsom signed Friday, was limited to requiring each regulated utility that owns transmission to annually prepare a report for the CPUC “on any changes to previously reported in-service dates of transmission and interconnection facilities necessary to provide transmission deliverability to eligible renewable energy resources or energy storage resources that have executed interconnection agreements.”
Two bills that failed were:
SB 1032, also by Becker, that sought “faster and cheaper transmission development” by directing the CPUC to identify “proposals to accelerate the development of, and reduce the cost to ratepayers of expanding, the state’s electrical transmission grid as necessary to achieve the state’s goals [of reducing greenhouse gas emissions.]” Measures to be studied would have included public ownership of transmission facilities, public financing of transmission projects and the use of non-ratepayer funds to cover part of the cost of transmission projects needed to achieve the state’s clean energy goals. It died in the Assembly Appropriations Committee in mid-August.
AB 2696 by Assemblymember Eduardo Garcia (D-Coachella), chair of the Assembly Utilities and Energy Committee, was intended to lower the costs of transmission development. It would have told the CPUC, in consultation with CAISO and other entities, to study “potential lower cost ownership and alternative financing mechanisms for new transmission facilities needed to meet the state’s clean energy and climate targets” including public ownership, public financing and partnerships with federal agencies. It died in the Senate Appropriations Committee on Aug. 11.
A committee formed by Texas’ political leadership has produced what it calls a “comprehensive” state energy plan to guide lawmakers and stakeholders in making further changes to ERCOT’s wholesale market.
The State Energy Plan Advisory Committee’s (SEPAC) report identifies how Texas “can best adapt to the changing electric generation resource mix and support market-based incentives” that ensure the generation supply is “adequate, resilient and poised to support the continued economic growth in this state” as a key problem.
The report says witnesses who provided testimony during one of the committee’s two meetings acknowledge intermittent renewable resources have provided additional capacity and low-cost energy, but that they have also introduced new “operational challenges.”
“The key reliability issue facing ERCOT will be to ensure adequate dispatchable generation is available during times of low non-dispatchable output,” the report says, calling for a clear reliability metric or standard. “The committee believes this is a necessary first step in evaluating the efficacy of the proposals under consideration. … The more that power systems rely on wind, solar and battery storage systems, the greater the risk that a major grid disturbance will cause the grid to cascade into a blackout condition.”
SEPAC recommends that renewable resources be required to “firm their deliveries” with dispatchable generation. That would burden renewables with additional costs in a market designed to pay generators for the energy they produce.
“The committee does not support a market design that favors new or subsidized generation over existing resources, as doing so could create regulatory inefficiencies and raise capital costs for Texas ratepayers,” it said.
According to the report, the committee found “broad support for favoring competitive solutions to manage the uncertainty that ERCOT presently is addressing through out-of-market reliability actions.” The grid operator’s conservative operations posture, where it keeps several thousands of megawatts of resources in reserve, has led to billions in additional operating costs and wear and tear on generators.
Joel Mickey, one of SEPAC’s 12 members and a former ERCOT staffer, concurred with the overall report — approved by a 7-5 vote — in an appended statement because of the report’s statutory deadline to be submitted to the Legislature. However, he dissented on two additions that he said were added at the last minute. (See “Energy Advisory Committee OKs Report,” ERCOT Could Name New CEO this Week.)
“These additions, in my opinion, have not been adequately vetted and could cause significant reliability problems within the [ERCOT] grid,” Mickey said, referring to the recommendation requiring renewable resources to pay for dispatchable energy and SEPAC’s lack of support for a market design that favors other resources over existing generation.
“I strongly support the competitive market structure in ERCOT and the competition among generators and retail electric providers that provide the best solutions [for Texas]. I believe these additional recommendations undermine the benefits of competition that ensure reliable, clean, affordable electric service,” he wrote.
Mickey, who now consults in the energy sector, said the recommendation that renewables firm their energy delivery with a competitor’s generation output is “discriminatory and ignores the fundamental purpose of ERCOT as an [ISO]: … the ability to take the energy offered from many diverse resources and to deploy those resources.”
“My second concern is the discriminatory application of this recommendation which can be expected to result in thousands of megawatts of existing renewable generation resources shutting down if forced to purchase large amounts of power from their competitors,” he said. “This recommendation will discourage new renewable generation from being added to the ERCOT grid. Both results will reduce reliability in ERCOT and increase the likelihood of emergency conditions or rotating outages.”
Noting ERCOT resources are paid the same market price for energy produced, Mickey argued that if SEPAC’s policy is to discourage favoring any subsidized generation resources, “then it would be important that the state of Texas account for and eliminate the benefits of all direct and indirect state and federal tax breaks, tax incentives and any other subsidies for all existing nuclear, coal, gas and hydro generation resources to ensure that all generation resources are held to the same standard.”
R Street Institute senior fellow Beth Garza, who testified before the committee during its first meeting, agreed with Mickey’s comments. ERCOT’s former market monitor, Garza said forcing renewables to “firm their deliveries” with dispatchable generation would “hamstring” the ISO’s ability to operate the market efficiently and reliably.
“One exception is their recommendation that ‘the [Public Utility Commission] should define a clear reliability metric or standard for the ERCOT region,’” Garza told RTO Insider. “I believe this to be an essential precedent to making any significant market design change.”
Other committee members also added concurring and dissenting opinions. Several noted they had not yet seen the final product, and one supplied revisions that she hoped would be included in the report.
Mark Ammerman, a retired Houston banker, called the committee’s work “inadequate,” saying it was tasked with producing a plan, not a report. He said he did not consent to the final product because the committee had not addressed the key mandates of the legislation that created the committee.
“The requirement of the Senate bill to perform the above analysis and recommendations by Sept. 1, 2022, became impossible when this committee only met for the first time in July,” Ammerman said.
The committee was created by legislation passed last year and charged with preparing a state energy plan that evaluates ERCOT market’s structure and pricing mechanisms, as well as barriers preventing “sound economic decisions.” The plan was also to look at ways to improve the grid’s reliability, stability and affordability.
The report also notes actions the PUC and the Texas Railroad Commission (RRC), which regulates the intrastate gas industry, have taken to improve coordination between the two sectors and protect them before the next winter storm.
Alison Silverstein | Texas Tribune
“To [paraphrase] Gertrude Stein, ‘There’s not much there there,’” Alison Silverstein, an energy consultant after a regulatory career with the PUC and FERC, said in an email. “Despite the statutory charges to [SEPAC], this report isn’t an evaluation of market structure, pricing mechanisms or methods to improve those, nor is it a ‘state energy plan’ for how to improve state electricity and gas markets. Rather, this is merely a recitation of steps the PUC and RRC are already doing and some cheerleading to keep doing that stuff.
“Because SEPAC performed no analysis or critical scrutiny, its report falls hook, line and sinker for the proposition that ERCOT needs more dispatchable resources, and for the extraordinarily bad and expensive idea that intermittent generators should firm their deliveries using dispatchable generation technologies,” she said.
“Most of their recommendations seem to take the form of, ‘Keep doing what you’re doing,’” concluded Garza, who previously called the committee’s work a “check-the-box exercise.”
It does acknowledge the thermal outages that occurred during the 2021 storm and the FERC/NERC report that highlighted natural gas’s role in fuel supply issues. (See FERC, NERC Release Final Texas Storm Report.)
Gov. Greg Abbott, Lt. Gov. Dan Patrick and House Speaker Dade Phelan each appointed four of SEPAC’s members. It was chaired by Lower Colorado River Authority General Manager Phil Wilson, whose staff wrote much of the report.
The CAISO Board of Governors on Wednesday extended reliability must-run (RMR) contracts for a group of small, aging natural gas plants that the ISO says are needed for summer grid reliability.
The generating units have capacities of 27.5 to 248 MW, with most on the low end of that range.
“The Board’s action is part of its focus, along with state energy agencies, to make sure all available generating capacity can be used during the summer months, when stressed conditions on the grid are most common,” CAISO said in a news release.
RMR contracts require power plants to continue operating to meet systemwide and local capacity needs for the term of the agreements in return for additional compensation.
The governors made their decision during an unusually short monthly meeting held on the same afternoon as a severe heat wave descended on the West and the ISO issued its first energy emergency alert of the summer.
The ISO’s original approval of the RMR contracts, starting in 2019, was part of its push to keep all available resources running after the ISO projected possible summer shortfalls from 2020 through at least 2024. Energy emergencies in August and September 2020 and again in July 2021 appeared to confirm those projections.
Generators can be released from RMR contracts if they sign resource adequacy capacity contracts, another way of ensuring they keep operating.
“Total capacity and the number of resources under reliability must-run contracts with the ISO has been significantly reduced since the implementation of the state’s resource adequacy program and the addition of new grid facilities,” Neil Millar, CAISO vice president of infrastructure and operations planning, said in his memo to the board. “However, reliability must-run contracts remain an important backstop instrument to ensure reliability when other alternatives are not viable.”
The plants for which contracts were extended through 2023 are the California State University-Channel Islands Site Authority’s Channel Islands Power plant (27.5 MW), Starwood Energy Group’s Greenleaf II Cogen plant near Yuba City (49.2 MW), Dynegy Oakland’s Units 1 and 3 (55 MW each), and two Midway Sunset Cogen units in a Kern County oil field (totaling 248 MW).
Another unit, the KES Kingsburg, LP Kingsburg Cogen plant (34.5 MW) will be released from its RMR contract at the end this year after signing a multiyear resource adequacy capacity contract.
“The Dynegy Oakland resources are required to meet the 2023 local capacity requirement in the Oakland sub-area of the Bay Area local area,” pending the completion of transmission projects and a 55-MW battery system, Millar wrote.
“Greenleaf II Cogen continues to be required to meet the 2023 local capacity requirement in the Drum-Rio Oso sub-area of the Sierra local area,” he said. “The sub-area local capacity requirement was determined to be 750 MW, and there are only 558 MW (553 MW at peak) of total available resources in the sub-area including the Greenleaf II Cogen unit.” A 230/115-kV transformer project is expected to mitigate the reliability need by March 2024, he said.
CAISO needs the Channel Islands and Midway Sunset units to meet 2023 and 2024 systemwide reliability requirements.
“The critical concern at this time is the dependence on a significant volume of new construction required in 2026 — over 6000 MW of additional net qualifying capacity — to meet the mid-term reliability authorization amounts set out [in a decision] by the [California Public Utilities Commission],” the memo says.
“Further, this development is coming on the heels of two years of already aggressive development to meet 2022 and 2023 requirements. If half of the 2024 procurement is delayed, the ISO would fall below the [necessary] 18.5% planning reserve margin requirement. … Management considers this to pose a risk to reliability at this time.”
CAISO also is talking with the governor’s office about making the units part of the state’s new multibillion dollar strategic reliability reserve in hopes of avoiding the RMR extension, Millar said.
Brazos Electric Power Cooperative has offered to pay ERCOT as much as $1.44 billion in its proposed exit plan from Chapter 11 bankruptcy and settle its dispute with the Texas grid operator over astronomical wholesale power prices in the wake of the February 2021 winter storm.
Under the terms of a settlement agreement and reorganization plan filed Thursday with the U.S. Bankruptcy Court for the Southern District of Texas, Brazos will make an initial payment of $1.15 billion. It will then make annual payments to ERCOT of $13.8 million for 12 years and contribute a portion of the sale of its generation assets, about $116.6 million, to fund payments through the grid operator to market participants still short from market transactions during the week of the storm (21-30725).
The initial lump sum will be used to help replenish a fund ERCOT used to settle transactions following the storm and to finance an initial distribution to market participants that joined in the settlement.
ERCOT had no comment on the filings, keeping with its practice of not remarking on legal matters. However, it told stakeholders in a market notice that it has not yet reached a final agreement on “certain important provisions in the plan.” It also noted that both the plan and a disclosure statement are working drafts and will be amended to reflect ongoing discussions and negotiations with Brazos and other key stakeholders.
The bankruptcy court has scheduled a hearing for Sept. 14 to determine whether the plan meets U.S. Bankruptcy Code requirements. Assuming confirmation, Brazos will then begin soliciting votes, due Oct. 27, from ERCOT and market participants on the agreement. Another hearing has been scheduled for November to consider final approval of the settlement and reorganization plan.
Brazos filed for bankruptcy in March 2021 after receiving an invoice from ERCOT for $2.1 billion in market transactions that it was short the market, with payment due in a few days. The cooperative responded with a force majeure event letter and by disputing the charges. (See ERCOT’s Brazos Electric Declares Bankruptcy.)
The co-op then opened an adversary proceeding against ERCOT in August 2021, challenging the Public Utility Commission’s emergency orders directing the grid operator to set prices at their $9,000/MWh limit to reflect the scarcity in the market. It sought to reduce the short-pay claim by at least $1.1 billion, the amount it attributed to ERCOT’s administrative adjustment.
Wholesale prices remained at their maximum for four straight days after the grid came within minutes of total collapse. ERCOT also increased ancillary fees to more than $25,000/MWh as it desperately sought to balance demand with load after a devastating loss of generation that led to long-term blackouts.
“The consequences of these prices were devastating to Brazos Electric and its members,” the cooperative said in its restructuring plan.
The adversary proceeding trial began earlier this year but was suspended after several weeks to allow the parties to mediate the dispute. (See ERCOT, Brazos Agree to Mediation in Dispute.)
ERCOT has said that almost all of the Brazos short-pay claim should be entitled to priority treatment as an administrative expense claim in the bankruptcy case. The short-pay amount has been revised to $1,886.6 billion, which will be fully recovered.
When Brazos comes out of bankruptcy, it has agreed to sell its generating assets, which total about 4 GW of capacity, and transition from a generation and transmission cooperative to a transmission and distribution cooperative. All of Brazos’ generation is natural gas-fired.
Under the agreement, Cliff Karnei, Brazos’ general manager since 1997, and three other members of the cooperative’s senior management will leave their jobs by March 2023. In addition, Karnei and two others will be barred from working for any ERCOT market participant if they’re acting as a financial counterparty to the grid operator.
Karnei resigned from ERCOT’s Board of Directors last year shortly after the storm hit, ending two decades of service on the board.
California lawmakers passed a last-minute package of climate and energy bills on Wednesday night that Gov. Gavin Newsom wanted to bolster grid reliability and reduce greenhouse gas emissions.
The last day of the 2021/22 legislative session saw lawmakers vote to reverse the state’s decision to close its last nuclear plant, Pacific Gas and Electric’s Diablo Canyon facility, by 2025. The Senate and Assembly approved Senate Bill 846, which grants PG&E a $1.4 billion forgivable loan to keep Diablo Canyon operating five years beyond its scheduled retirement.
The plant supplies nearly 9% of the state’s electricity needs and 17% of its carbon-free energy, the measure says.
“Preserving the option of continued operations of the Diablo Canyon powerplant for an additional five years beyond 2025 may be necessary to improve statewide energy system reliability and to reduce the emissions of greenhouse gases while additional renewable energy and zero-carbon resources come online,” it says.
Newsom, who backed the bill, signed it Friday. Continued operation of Diablo Canyon will require approval of the U.S. Nuclear Regulatory Commission.
Grassroots advocacy group Californians for Green Nuclear Power (CGNP) has pushed for the move since before many politicians were convinced that keeping the plant open made sense. Newsom and other officials gradually came around to CGNP’s point of view as the state struggled to maintain grid reliability starting with the rolling blackouts of August 2020.
“This has been the culmination of a decade of work for CGNP, of thousands of hours of research, filings, outreach and testimony,” the group’s president, Carl Wurtz, said in a prepared statement. “It’s unfortunate it took the lights going out for many to appreciate Diablo Canyon’s value, but better late than never.”
Others continue to believe nuclear power is wrong for California. A contingent of lawmakers said the $1.4 billion could be better spent on fast-tracking more solar, wind and storage resources to meet the state’s goal of relying on 100% clean energy by 2045.
Negative reaction to SB 846’s passage included a statement by the nonprofit Environmental Working Group saying, “This action can only hurt the state’s shift to safe, renewable energy and prolong the risk of a disaster at the plant.” The “bailout bill” was rushed through the Legislature at Newsom’s bidding in the last week of the session, with little time for review by lawmakers and the public, it said.
“The bill … which goes into effect immediately, extends the plant’s carefully planned and negotiated [retirement],” EWG said.
A 2016 agreement among PG&E and environmental and labor groups initially laid out plans for Diablo Canyon’s closure. The California Public Utilities Commission in January 2018 approved the 2,200-MW plant’s retirement. The bill invalidates that decision while ordering the CPUC to reopen its Diablo Canyon proceeding.
SB 846 also instructs the CPUC to submit to the Legislature a cost-benefit analysis of keeping the plant open from 2024 to 2035 compared with adopting a portfolio of “other feasible resources” consistent with the state’s greenhouse gas reduction goals, and a “reliability planning assessment” with supply-and-demand forecasts for five- and 10-year periods under several risk scenarios.
Climate Bills
Other measures passed by lawmakers this week at Newsom’s behest included:
Assembly Bill 1279, the “California Climate Crisis Act,” which would codify former Gov. Jerry Brown’s 2018 executive order requiring the state to become carbon neutral by 2045 and to “achieve and maintain net-negative greenhouse gas emissions thereafter.”
SB 1020, which would establish new interim targets for the state’s effort, under 2018’s Senate Bill 100, to supply all retail customers with 100% zero-carbon energy by 2045. The bill would make it state policy to supply 90% clean energy to retail customers by the end of 2035, upping that amount to 95% by Dec. 31, 2040.
SB 905, which would require the California Air Resources Board to establish a program to capture and store carbon dioxide, and AB 1757, which would task the state’s Natural Resources Agency with establishing ambitious carbon sequestration targets for “natural and working lands” by Jan. 1, 2024.
One Newsom-backed bill failed Wednesday. AB 2133 would have accelerated the state’s GHG reduction goals from 40% below 1990 levels to 55% below those levels by 2030. The bill failed in the Assembly after members of the lower house could not agree to support some Senate amendments.
