A program described as a first-of-its-kind incentive for medium- and heavy-duty ZEV infrastructure in California is now accepting applications for hydrogen fueling projects.
The program, called Energiize, opened the application period on June 30. The deadline to apply is July 14 at 5 p.m.
The competitive funding round will award a total of $17 million in incentives. The incentives will cover up to half the cost of a hydrogen fueling station project, helping to pay for equipment such as hydrogen dispensers, piping and point-of-sale systems.
The maximum incentive is $3 million. But so-called Jump Start projects are eligible for incentives covering 75% of costs, up to a maximum of $4 million.
Applicants potentially eligible for Jump Start include small businesses, certified minority businesses and veteran-owned small businesses. Public transit or school district projects built in disadvantaged communities may also qualify.
The program is open to commercial fleet or vehicle operators, or vendors applying on their behalf. The project may be a new fueling station or expansion of an existing station.
Speeding Infrastructure Roll-out
Energiize, whose full name is Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles, is being funded by the California Energy Commission.
In March 2021, the CEC selected CALSTART to design and run the program. Energiize has a total authorized allocation of $276 million through 2026.
The CEC described the program as a first-of-its-kind project intended to speed the deployment of medium- and heavy-duty ZEV infrastructure to accommodate future ZEV fleets.
Energiize will help the state meet the goals of an executive order that Gov. Gavin Newsom issued in September 2020, requiring all medium- and heavy-duty vehicles in the state to be zero-emission by 2045, where feasible, the CEC said.
Energiize opened its first round of funding in March. Called EV Fast Track, the incentives were aimed toward charging infrastructure for commercial fleets of medium- and heavy-duty battery-electric vehicles.
The EV Fast Track incentives were offered on a first-come, first-served basis. The $16.24 million in incentives were snapped up within seconds.
The incentives went to nearly 40 applicants across California, to commercial transportation operations including drayage, refuse, school bus and delivery services. And 85% of applicants qualified for the larger Jump Start incentive, CALSTART said in a release.
In addition to the EV Fast Track and hydrogen fueling funding lanes, Energiize will offer incentives this year for public charging infrastructure and EV Jump Start applicants.
Application Process
EV Fast Track is the only Energiize funding lane that is first-come, first-served. Incentives in the other lanes, including hydrogen fueling, will be awarded on a competitive basis.
A recent CALSTART webinar explained the application and scoring process for hydrogen fueling infrastructure incentives.
Applicants must submit information including proof that they’ve met the project’s first “critical milestone,” which is securing the project site through means such as an easement or executed lease.
Applicants must provide confirmation from the local utility that the site is prepared to receive the energy needed for the infrastructure project.
Applicants must also answer three “qualitative” questions. The first asks how the infrastructure will target medium- and heavy-duty ZEVs, and how the operator plans to get the most use out of it over time.
The applicant is asked to detail community buy-in and support for the project. The third question is about benefits the project will provide for local residents, such as paid workforce development opportunities, expanded transit service or hydrogen fueling discounts.
Incentive recipients will be required to operate the equipment in California for at least five years.
“This is a big investment,” said Amy Gower, a CALSTART lead project manager. “We want to make sure that this infrastructure is in the ground for as long as possible.”
VALLEY FORGE, Pa. — PJM consumer advocates and transmission owners appear headed for a showdown over a proposed initiative to review the RTO’s use of designated entity agreements (DEA).
Consumer advocates narrowed their differences with TOs but were unable to “get across the finish line” with a consensus issue charge, Denise Foster Cronin, of East Kentucky Power Cooperative, told the Markets and Reliability Committee at its meeting Wednesday.
As a result, members will be asked at the MRC’s meeting this month to choose between two competing issue charges for a review of the DEA and PJM’s use of it, including potential changes based on the experience with the implementation of FERC Order 1000.
The major difference between the two issue charges, Foster Cronin said, was TOs’ insistence that revisions to the rights and responsibilities of PJM and the TOs under the Consolidated Transmission Owners’ Agreement (CTOA) be out of scope.
The initiative arose from a 2018 FERC order rejecting PJM’s request to revise the Operating Agreement to exempt incumbent TOs from executing the DEA (ER18-1647). (See FERC Rejects PJM Exemption for Incumbent TOs.)
PJM had proposed two changes to the competitive proposal window process mandated by Order 1000. The commission approved PJM’s request to allow transmission developers 60 days to accept a DEA after receiving it as the winner of a competitive project under Order 1000.
But the commission rejected the request to exempt incumbent TOs from executing a DEA for Regional Expansion Transmission Plan (RTEP) projects that the OA requires PJM to designate to an incumbent. Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not cost allocated outside.
The commission rejected TOs’ rehearing request in 2019, saying that breaching a DEA is more expensive for nonincumbent TOs, which are subject to meeting construction milestones that may be delayed for reasons beyond their control while incumbent TOs only risk breaking the terms of a CTOA by missing scheduled in-service dates.
Unlike incumbents, nonincumbents must also “obtain a letter of credit or other financial instrument equal to 3% of the incremental project cost in the event of a breach,” meaning this extra cost must factor in project submissions, making the incumbent TO’s proposal cheaper by default, FERC said. (See Rehearing Denied on PJM Designated Entity Agreements.)
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said his group was unable to reach agreement on the scope of the issue charge despite six hourlong meetings with the TOs.
Poulos said the advocates question whether PJM is complying with schedule 6, section 1.5.8 of the OA, which requires entities assigned to construct and operate RTEP projects to comply with the DEA. PJM is not requiring incumbents to sign DEAs for all the situations identified in the OA, he said.
“We’re concerned that the language of the issue charge brought by the TOs could eliminate some of the projects” FERC intended to have covered by DEAs, such as immediate-need projects, he said.
The advocates’ issue charge includes a goal of ensuring “appropriate consumer protections” are followed by entities assigned to construct RTEP projects.
Steve Lieberman, of American Municipal Power, said PJM is “in a little bit of hot water” for not interpreting the OA as FERC directed.
“I’m not sure PJM would agree to that characterization,” responded Stu Bresler, the RTO’s senior vice president of market services.
“Our goal is making sure we’re treating everyone fair and equitably,” said Ken Seiler, PJM’s vice president of planning.
Foster Cronin said the TOs would like to review the DEA’s security requirements and development milestones to see if there are opportunities to streamline it based on PJM’s experience with Order 1000 over the last decade. “No developer should bear costs that don’t provide benefits,” she said.
Susan Bruce, representing the PJM Industrial Customer Coalition, said her group supports the broader look that CAPS proposed.
Alex Stern of Public Service Electric and Gas said the advocates’ issue charge doesn’t address the concern raised by FERC but raised a “new issue on how to apply more stringent requirements” on incumbents.
“It’s too simplistic to say PJM should just comply with the language” of the OA, he said. “We’re all confused.”
PJM Regroups After Opposition to Request for Service on FERC Filings
VALLEY FORGE, Pa. —Facing stakeholder opposition, PJM officials last week withdrew what they hoped would be a routine rule change requiring that the RTO be served with FERC filings affecting it.
PJM attorney Steve Pincus told the Markets and Reliability Committee on Wednesday that the RTO sought the change to ensure it can respond within FERC’s deadlines to any filings that affect it or its members.
The RTO’s current rules require only that transmission owners serve it with any Federal Power Act Section 203 filings. The rules do not cover waiver filings, settlements or reliability-must-run requests, Pincus said.
“This is a really bad idea,” American Municipal Power’s (AMP) Steve Lieberman responded, saying PJM’s proposed issue charge was overly broad and would create burdens for members. He recommended the RTO attempt a “more surgical approach.”
“AMP has a team of people … that monitor the dockets that get filed. I don’t know why PJM can’t as well,” Lieberman said. Members might inundate PJM with irrelevant filings out of concern that a failure to serve the RTO could lead to a FERC enforcement action, he argued.
Constellation Energy’s Jason Barker said his company would support PJM’s problem statement even though it disagrees with the RTO’s proposed solution. He recommended the RTO convene a meeting of FERC practitioners from member companies to devise a solution.
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed. “The lawyers need to be in the room for this,” she said. “We all have that risk [of missing a filing], and we all look at the Federal Register.”
Adrien Ford, of Old Dominion Electric Cooperative, suggested that, rather than the MRC, the matter be considered by a special task force, the Risk Management Committee or the Governing Document Enhancement & Clarification Subcommittee, as others suggested.
Pincus assured members that PJM was not attempting to create a “compliance trap” for them but a “safety net” for itself. “We obviously monitor FERC filings, but the territory we have to cover is far greater than any other member,” he said. “To me it seems like a no-brainer. It seems logical that PJM would receive service.”
But Pincus acknowledged he was unaware of any instances in which the RTO was denied the ability to file comments because of missed deadlines.
“It’s a solution in search of a problem,” said Paul Sotkiewicz, representing J-POWER USA.
In the face of the opposition, General Counsel Chris O’Hara told members that the RTO would withdraw its request to approve the issue charge pending additional discussions.
But he said the rule change was needed, calling it “unconscionable that a generation owner can make a 203 filing [affecting PJM] and not serve us.”
Independent Market Monitor Joe Bowring said he shares the RTO’s concern about not being served in relevant dockets. “Whatever the solution is for PJM, we would like to apply to us as well,” he said.
Revised Operating Committee Charter Approved
Members unanimously endorsed a five-word change to the Operating Committee’s charter to reflect the RTO’s changing generation mix. The revised charter adds the words “reliability attributes and pertinent conditions” to paragraph 7, which refers to the committee’s oversight of operating practices and procedures relating to reliability.
Stakeholders Wary of ‘Narrow’ Change to Market Seller Offer Cap
Members and the Monitor expressed concern over PJM’s proposal to revise the market seller offer cap (MSOC) in time for the 2024/25 capacity auction in December.
PJM’s Pat Bruno said what he called a “narrow” change to the MSOC “seemed to have a broad consensus with stakeholders,” citing discussions by the Resource Adequacy Senior Task Force (RASTF).
Bruno said the change would ensure sellers are always able to represent the cost of their Capacity Performance risk when offering into the auction. The MSOC would be set at a level equal to the greater of the CP quantifiable risk (CPQR) or net avoidable-cost rate (ACR) inclusive of CPQR.
The change would address circumstances in which a unit with a positive CPQR value has that cost offset by an otherwise negative net ACR, which could result in a $0 offer cap.
Bruno gave an example of a wind farm with an ACR (excluding CPQR) of $80/MW-day, a CPQR of $20, and an energy and ancillary services offset (E&AS) of $150.
Under current rules, the generator would bid $0 ($80 + $20 – $150 = -$50). Under the proposed rules, the generator would offer at the CPQR: $20/MW-day.
“We think that’s consistent with how a market seller would set a competitive offer,” Bruno said.
PJM plans to seek endorsement of the change at the MRC’s meeting this month.
Jeff Whitehead of GT Power Group and Becky Robinson of Vistra said they support the change. But Bowring called the proposal “premature and inappropriate,” saying it would be a “significant redefinition” of the CPQR, undermining the capacity MSOC that protects against the exercise of market power.
“It’s not a problem that needs to be fixed,” Bowring said. “We haven’t had a $0 capacity clearing price, and we’re not likely to. But if we do, it would reflect competitive offers and a competitive outcome.”
Market sellers can include the cost of mitigating risk under the existing rules, Bowring said in an email after the meeting. He said although PJM has not defined CPQR in this proposal, the RTO has proposed a significant broadening of the definition of CPQR in RASTF meetings.
“If PJM wants to propose a change, PJM should make a proposal with all relevant elements clearly defined so that the full implications can be understood,” he said. “PJM has not explained why CPQR should uniquely not be part of gross ACR. PJM has stated, without explanation, that net revenues do not offset CPQR. That is not consistent with the definition of a competitive offer.”
AMP’s Lieberman also expressed concern, saying stakeholders should agree first on a definition of CPQR.
“Saying this is ‘narrow’ doesn’t make it so,” he said. “This is potentially setting a floor on the market seller offer cap.”
BRA Results Discussed
PJM’s Pete Langbein gave members a brief presentation on the results of last month’s 2023/24 Base Residual Auction.
Prices dropped by one-third to almost one-half in the auction, the first since the virtual elimination of the minimum offer price rule (MOPR) for subsidized resources and institution of a tougher offer cap. It was the RTO’s lowest prices except for 2012/13 and 2013/14. (See Low PJM Capacity Prices No Bargain, Coal & Gas Generators Say.)
Langbein said the Commonwealth Edison and Duke Energy zones didn’t bind, unlike in the prior BRA.
“We were concerned by the prices we saw,” commented Aaron Breidenbaugh, of Centrica Business Solutions. “It’s a disturbing trend if you’re on the supplier side.
PJM Senior Vice President of Market Services Stu Bresler said total capacity offered was about 11,000 MW less than in the previous auction.
PJM Sets Workshops on Extreme Weather NOPR
Ken Seiler, PJM’s vice president of planning, said the RTO will hold stakeholder workshops on July 21 and Aug. 12 on FERC’s June 16 Notice of Proposed Rulemaking on transmission planning performance requirements for extreme weather (RM22-10). The NOPR would direct NERC to modify reliability standard TPL-001-5.1 (Transmission system planning performance requirements).
FERC issued another NOPR on June 16 to solicit one-time reports from transmission providers detailing their “current or planned policies and processes for conducting extreme weather vulnerability assessments and mitigating identified extreme weather risks” (RM22-16, AD21-13). (See FERC Approves Extreme Weather Assessment NOPRs.)
VALLEY FORGE, Pa. — PJM members will take more time to consider a proposal to require that at least one of the nine members of the RTO’s Board of Managers has “expertise in the transition to zero-carbon energy resources.”
Dave Kolata, executive director of the Illinois Citizens Utility Board (CUB), proposed the change to section 7.2 of the Operating Agreement at the Members Committee meeting Wednesday, asking that it be brought to a vote at the committee’s July meeting. Albert Pollard, a former Virginia legislator who heads CUB’s CLEAR-RTO project, said the change would allow “strategic-level peer-to-peer leadership.”
After a lengthy discussion, the sponsors agreed to withdraw their request for an immediate vote; talks are expected to continue at the next MC meeting.
Kolata and Pollard noted that many of PJM’s utilities and most of its states have clean energy commitments and that the RTO’s interconnection queue is overwhelmingly solar, wind and storage.
“As the resource mix changes, PJM’s board will need an ever deeper understanding of the risks and opportunities of balancing the spectrum of clean energy resources (nuclear, wind, solar, [distributed generation and demand response]), as well as the need for dispatch of thermal resources,” CUB’s presentation said.
Cypress Creek Renewables and Jim Davis of Dominion Energy endorsed the proposal. Brian Kauffman of Enel X North America said the proposal is a “common sense next step.”
But John Horstmann of AES said he was concerned about changing the OA without going through the Consensus Based Issue Resolution (CBIR) process, with a problem statement and issue charge. “I have a concern about this setting a precedent,” he said. “There’s things many of us would like to change in the OA.”
“I think policy questions of this narrow scope are appropriate” for this format, Pollard responded.
Constellation Energy’s Jason Barker said his company supports the idea “in concept” and that the MC was the appropriate venue to consider such a change. But he said the proposal was vague as written. “It doesn’t say how the Nominating Committee should assess” the qualifications, he said.
Paul Sotkiewicz, representing J Power USA, said he shared Hortsmann’s concern over an immediate up or down vote and would oppose the proposal. “What about a board member for DR or combined cycle gas turbines or coal or nuclear units,” he said. “Where does it stop?”
Kolata responded that his goal is ensuring reliability. “The intent is not to provide preferences for any kind of resource,” he said.
Adrien Ford, of Old Dominion Electric Cooperative, said PJM should make sure any change doesn’t delay its current search for a replacement for Manager Sarah Rogers, whom Ford said is likely to resign after the July meeting.
Kolata said the change would require FERC approval and thus wouldn’t take effect immediately.
PJM’s Dave Anders asked whether the proposal could mean “open season on rewriting the qualifications” for board members.
“We view this as discrete. We don’t view this as open season,” Kolata responded. But he acknowledged “others may make suggestions.”
MC Chair Erik Heinle, who represents D.C.’s Office of the People’s Counsel, said the committee would have further discussion on the proposal this month.
Members Debate Change to CBIR Matrix Procedure
The committee also discussed a proposal by Horstmann to revise the RTO’s rules to allow PJM staff to “seed” the blank matrix used in the CBIR matrix with potential options before stakeholders begin work on it.
Horstmann said the change to Manual 34: PJM Stakeholder Process would improve efficiency as members consider options for each design component.
Ford said the change would be helpful. “It’s hard to start from a blank sheet,” she said. She said concerns that it would give the RTO an advantage in the subsequent debates were addressed by a change allowing other stakeholders to also submit options before the first meeting at which the matrix is developed.
But Independent Market Monitor Joe Bowring expressed concern. “I don’t think it’s a good idea. I think it does give PJM a first-mover advantage” even with the revised language, he said.
The committee will be asked to approve the change at its meeting this month.
Members Continue to Work on Relationship with New Board
ERCOT stakeholders last week continued to review and tinker with their processes as they work to forge a stronger working relationship with the grid operator’s new Board of Directors.
The Technical Advisory Committee has been directed by the board to come up with a procedural framework to “better involve the board and help educate the board.” The committee’s leadership has also been tasked with creating opportunities to interact with the board’s newly created Reliability and Markets (R&M) Committee.
The new board group has not finalized its charter yet, but it will be responsible for overseeing ERCOT’s core functions: planning, markets, reliability and resilience, and technology-related functions like information technology and project delivery.
That would seem to place another layer between the board and TAC. The stakeholder committee, comprising 30 market participant representatives in seven market segments, is assisted by four subcommittees and makes recommendations to the board regarding ERCOT policies and procedures. TAC is also responsible for prioritizing projects through protocol revision requests, system change requests and guide revision processes.
However, TAC Chair Clif Lange said the group will still have a direct line of communication with the board.
“[We’ll] still report to the board any activities that we’ve undertaken, and any sort of decisions that we’ve rendered in terms of interacting with the R&M Committee,” he said during TAC’s monthly meeting June 27, basing his comments on discussions he and Vice Chair Bob Helton have had with Directors Bob Flexon and Peggy Heeg.
TAC’s proposed reporting structure to the board’s Reliability and Markets Committee | ERCOT
The board now comprises eight independent directors, the Office of Public Utility Counsel’s interim public counsel and two nonvoting ex officio members. They replace a hybrid board of independent directors and market segment representatives that held office during the February 2021 winter storm and was criticized for not living in the state.
Flexon chairs the R&M Committee. He and Heeg will meet with Lange and Helton on July 11 to review TAC’s proposed procedural framework.
They agreed to put together a liaison delegation to advise and educate the R&M Committee on TAC decisions. The group would comprise TAC’s leadership and seated members as chosen by the seven market segments, with two representing the customer segment.
TAC wants to avoid a rigid formal structure with the delegation. Instead, members are recommending a conversational dialogue and inviting the board and R&M Committee to attend or listen to TAC meetings.
Addressing board concerns that ERCOT’s stakeholder-approval process takes too long, members have proposed a “shot clock” for revision requests by allowing a rule change’s sponsor to request a decisive vote be taken at TAC or the subcommittee level. A seconding motion would not be required, and motions to table would not be allowed to trump the vote.
The June Technical Advisory Committee meeting | ERCOT
“The stakeholder process has been a very effective way to help ensure that we have as few unintended consequences as possible … and having all of these different viewpoints weigh in. We actually get a better product because of that,” Golden Spread Electric Cooperative’s Mike Wise said, expressing the concerns of several other members. “I don’t want to [bypass the stakeholder process]. I think we should be concerned about it. But to speed up the process, that’s another issue.”
TAC is also under pressure to accelerate directives from the Texas Public Utility Commission through the stakeholder process. Lange said the issue has been raised in several forums.
“Some commissioners have stated they have concerns with the time,” Lange said. “The board has explicitly stated that this was something they wanted stakeholders to address.”
The committee has responded by proposing that ERCOT continue to draft revision requests that result from commission orders and file them with the R&M Committee, which could endorse the request and advance it to the full board, refer it to TAC, or send it directly to a TAC subcommittee.
“I understand the commission’s frustration with the time to get some things done, but the problem is the devil’s really in the detail,” said Nick Fehrenbach, who represents the city of Dallas in the consumer segment. “It may be a great idea what they’re ordering us to do, but how do we change the protocols to where there’s not unintended consequences? Are we going to end up with a situation where we’re having to appeal approved protocols rather than the normal stakeholder process?
“The cure may be worse than the disease. We’re on very thin ice and a very slippery slope,” he said. “We need caution here.”
The committee is recommending the appeals process of its decisions remain the same, with appellants taking their claims directly to the board. It is also proposing appeals could also be made to the R&M Committee, with it providing an opinion to the board.
TAC is also proposing its members have five years of experience in the electric industry, with OPUC’s appointed representatives to a residential consumer seat being exempted. The members would be required to be certified by their employer that they are authorized to make segmental decisions, with alternate representatives expected to meet the same standards.
TAC leadership Bob Helton (left), Engie, and Clif Lange, STEC | ERCOT
“The board wants decision-makers, not note-takers,” Lange said.
Members pushed back against an earlier suggestion last year that TAC comprise officer-level representatives from their companies. (See “Members Push Back Against Revamped TAC Structure, Conservative Ops,” ERCOT Technical Advisory Committee Briefs July 28, 2021.)
TAC’s subcommittees are completing self-assessments to determine whether the groups are still necessary and whether additional efficiencies can be added as part of an annual review process. The subcommittee’s structural and procedural review meeting will be held in September.
SCT Project Moves Closer to Reality
TAC gave the Southern Cross Transmission (SCT) project — a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region — its biggest boost yet by endorsing the final three ERCOT white papers addressing PUC directives to determine how to reliably interconnect the project. (See Texas Regulators Boost Southern Cross Project.)
The committee endorsed, without opposition:
Directive 1: creates a new market participant type, “Direct Current Tie Operator,” after consultation with stakeholders. SCT has told ERCOT it does not plan to join an appropriate market segment at this time, leading staff to conclude no bylaw revisions are needed at this time.
Directive 11: finds that costs identified by the PUC have been appropriately addressed by resolving each of the commission’s 14 directives and through a memorandum of understanding between ERCOT and SCT.
Directive 12: determines that costs associated with DC tie exports have been sufficiently addressed by the other directives’ resolution and that no further revision to any cost allocation mechanism is necessary.
Garland Power & Light, which owns the project’s western endpoint and holds a certificate of convenience and necessity granted by the PUC in 2017, abstained from all three votes. Calpine and Luminant joined GP&L in abstaining from Directive 11.
Assuming the ERCOT board approves the white papers during its August meeting, that will only leave Directive 2, which requires the grid operator to enter a coordination agreement with the balancing authority on the eastern end of the SCT project. The project’s developers have said that directive is not necessary to the PUC’s review and can be completed and closed at a later date.
The project would be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line. The project has FERC approval and a waiver from its jurisdiction.
The project has been under regulatory review for more than seven years. PUC Commissioner Jimmy Glotfelty has taken the agency’s lead on SCT and filed a memo in January that said it’s time that the commission and ERCOT “close a chapter” on the project and allow it to “stand or fail on its own economic merits.” He believes the review can be finished by the end of October (46304).
“It appears that both ERCOT and Southern Cross are on the same page and have been working well together over the years with the goal of completing the review [and] directives,” Glotfelty wrote.
He suggested that interconnection and transmission planning issues associated with DC lines be included in a PUC rulemaking that would add a consumer benefit test for new transmission projects.
Staff Apologize for Credit Error
Kenan Ögelman, ERCOT’s vice president of commercial operations, apologized to members for the math error that led to the board last month tabling a rule change endorsed by TAC that lowers counterparties’ unsecured credit limit from $50 million to $30 million. (See ERCOT Board of Directors Briefs: June 21, 2022.)
“We should have caught that error. It’s a relatively easy check. I should have caught it,” Ögelman said. He said staff are developing a process going forward “where we triple check those results and catch errors before they make it out publicly.”
Staff’s June presentation to the board included a slide designed to show the drop in outstanding unsecured collateral as the limit is ratcheted down. Instead of decreasing the unsecured collateral for participants above the $30 million limit, the error decreased it to zero.
Ögelman said TAC would see the revised calculations during its meeting this month, with the board again taking up the issue during its August meeting.
“We pride ourselves in providing accurate analysis to both TAC and the board, and I don’t think we met that standard with that presentation,” he said.
Controllable Load Resource Changes
TAC took up only three changes during the meeting, endorsing a nodal protocol revision request (NPRR) and an accompanying other binding document revision request (OBDRR) on its consent agenda.
NPRR1131: changes controllable load resource’s participation in non-spinning reserve from offline to online non-spin. The change sets a bid floor of $75/MWh, equivalent to generation resources’ offer floor when providing online non-spin. If a qualified scheduling entity also assigns responsive reserve (RRS) and/or regulation up service to a controllable load resource that has been assigned non-spin, the sum of RRS, reg-up and non-spin ancillary service resource responsibilities will be assigned a $75/MWh offer floor.
OBDRR040: removes the controllable load resource providing non-spin schedules and regulation service schedules from the capacity calculations to align with NPRR1131.
The committee tabled NPRR1127, which clarifies the ERCOT entities required to have hotline and 24/7 communications with the grid operator and requires them to answer each hotline call.
The Governing Body of CAISO’s Western Energy Imbalance Market (WEIM) named a new chair and vice chair Wednesday and welcomed a new member, while honoring a longtime member who decided not to seek another term.
In its annual rotation of leaders, the Governing Body elected Robert Kondziolka and Jennifer Gardner to serve as its chair and vice chair, respectively.
Kondziolka, a veteran of Arizona’s Salt River Project, joined the WEIM’s five-member board in January 2020 and served as vice chair for the past year. On Friday he replaced outgoing Chair Anita Decker, who will remain on the Governing Body.
Kondziolka praised Decker for her efforts in a year when CAISO and WEIM reached a new power-sharing agreement and moved forward with plans for an the WEIM to launch an extended day-ahead market.
“Anita, thank you very much,” Kondziolka said. “We appreciate your leadership.”
Gardner, an attorney and independent energy consultant, was elected to her first term on the Governing Body in July 2021. She previously spent five years with environmental nonprofit Western Resource Advocates, where she directed its Regional Energy Markets Program.
The body reappointed founding member John Prescott to a third three-year term. Prescott was CEO of Pacific Northwest Generating Cooperative until his retirement in 2016, when he joined the inaugural Governing Body.
It also appointed a new member, Andrew Campbell, executive director of the University of California, Berkeley’s Energy Institute at Haas. He previously has worked as chief energy adviser to the California Public Utilities Commission.
WEIM Nominating Committee Chair Nicole Hughes said Campbell, who served on the WEIM Governance Review Committee for the past two years, was chosen from a group of well qualified candidates.
“Mr. Campbell has demonstrated wide-ranging expertise and experience that will help guide the ISO as it navigates issues relating to market rules of the Western Energy Imbalance Market and an increasingly changing energy and electricity market landscape,” Hughes wrote in a memo to the body.
Campbell replaces outgoing member Valerie Fong, who has been on the Governing Body since it was formed in 2016 but decided not to seek another term. Her colleagues thanked her in a resolution for her “outstanding service and dedication” to the WEIM.
NYISO on Tuesday reviewed with stakeholders the preliminary results and assumptions for the first phase of a two-part Grid in Transition study on the reliability effects of integrating increasing amounts of renewable resources into the power system.
“This first phase is really leveraging the Climate Change Phase 1 study case work, [which] was completed about two or three years ago,” Nicole Bouchez, principal economist for market design, told the Installed Capacity/Market Issues Working Group. “Because of that, the second phase is going to be coordinating with the 2022 planning studies.”
Phase one of the study is expected to be completed by end of this year.
For the second phase starting in August, the ISO will use its upcoming system and resource outlook study and policy case for scenario one (S1) and the NYSERDA integration analysis for the scenario two (S2) policy case. The 2022 effort will identify and quantify through a new study the potential level of system flexibility and grid attributes needed to reliably maintain system balance, Bouchez said. (See NYISO Launches 2022 Grid Planning Study.)
Load Shapes
NYISO staff incorporated stakeholder feedback into the study, including reliability and market considerations from Grid in Transition work performed last year. Staff also evaluated the results from phase one, including looking at load shapes, the distribution of hourly ramps and what multi-hour ramps look like, Bouchez said.
The first phase of the study is based on the Climate Change Phase 1 CLCPA Case load forecast data. | NYISO
A graph of summer peak load shapes for 2030 and 2040 showed essentially the same shape for policy cases S1 and S2 for 2030, while 2040 shows an obvious difference with a midday dip being exacerbated by projected additional solar output during midday intervals, she said.
The graph of winter peak load shapes for 2030 and 2040 shows a notable difference in the underlying load between the two. While the 2030 load shape looks not that dissimilar from existing load, “the real difference comes when we look forward to 2040 and see that the overall load has grown a lot with electrification … this is clearly a winter peaking scenario in 2040 between summer and winter, but because of the different builds you see the impact a different solar build has even in winter low solar circumstances,” Bouchez said.
The first key finding in the nearly complete system and resource outlook study is that the total installed generation capacity to meet policy objectives within New York is projected to range from 111 to 124 GW by 2040, more than double the 51 GW of generation capacity that exists and is contracted today.
Second, the study finds that the capacity contribution of intermittent renewable resources declines as more are added to the system. The limited contribution of incremental resources inhibits the ability of the power system to effectively meet mandatory resource requirements and to serve load in hours in which renewable generation is limited or unavailable.
Third, the outlook study finds that “if resources are not built in excess of reserve requirements to meet reliability margins, New York will likely import significant amounts of energy that may or may not be renewable. Even with additional imports, there could be significant renewable energy that is not deliverable to customers during peak producing hours.”
Next Steps
The ISO’s next steps include expanding the analysis to look at ramps when the net load does not become negative, considering stakeholder feedback, and drafting the phase one analysis portion of the report in early August,
“We’re going to be starting in July to work on the system and resource outlook study production cost data, which would be looking at both policy cases, but also will be looking at different loads at that point too, just like the outlook study looks at different loads in the S1 and S2 policy cases,” Bouchez said. “Our intent is to attempt to finalize the study in September. It may be a bit of a stretch goal, but we are trying to aim for that.”
SPP has issued its second conservative operations advisory this summer for its entire 14-state Eastern Interconnection footprint, effective noon CT Wednesday through 10 p.m. CT Friday.
The grid operator said it declared the advisory to hot temperatures, high loads and wind forecast uncertainty. That allows the RTO’s balancing authority to use greater unit commitment notification timeframes that include commitments before the day-ahead market and/or committing resources in reliability status.
No surprise, July is forecasted to be another hot month. | The Weather Channel
SPP issues conservative operations advisories when it needs to operate its system conservatively based on weather, environmental, operational, terrorist, cyber or other events. Generation and transmission operators have been provided instructions on applicable procedures and must report any limitations, fuel shortages or concerns.
July temperatures are expected to be above average and forecasts from the Texas Gulf Coast through the Central Plains and into Wyoming, according to the Weather Channel.
The Midwest Reliability Organization’s regional summer assessment, released last week, included SPP among the region’s balancing authorities likely to face capacity shortfalls this summer requiring external energy assistance or other emergency measures. (See MRO Warns Energy Emergencies Likely in Summer.)
Saturday’s advisory replaced a resource advisory issued Friday for the same period. SPP said conditions warranted the escalation to conservative operations.
Neither advisory requires public conservation.
The RTO also declared a conservative operations alert for June 21-24. It has issued four resources advisories since late spring.
California Gov. Gavin Newsom signed major legislation Thursday that would expedite permitting for new generation and storage facilities and potentially extend the life of aging gas plants and the state’s last nuclear power plant in an effort to maintain grid reliability during the coming summers.
Assembly Bill 205 and Senate Bill 122, introduced as placeholder measures in January, were rewritten and published as omnibus energy budget trailer bills on Sunday, with only a few days for public review. The State Legislature passed AB 205 on Wednesday night and sent it to Newsom to sign. Lawmakers voted on the Senate version Thursday and submitted it to the governor. Both bills will take effect at the start of the new fiscal year Friday.
The measures approved Newsom’s proposed $5.2 billion strategic reliability reserve consisting of “existing generation capacity that was scheduled to retire, new generation, new storage projects, clean backup generation projects, [and] diesel and natural gas backup generation projects.” (See Calif. Governor Proposes $5B ‘Reliability Reserve’.)
They also make the Department of Water Resources the backstop procurement agency for short- and mid-term reliability needs. That could mean purchasing energy from Pacific Gas and Electric’s Diablo Canyon nuclear power plant, scheduled to retire in 2025, and a fleet of aging natural gas plants along the California coast. The once-through cooling plants had been scheduled to retire in 2020 because of their destruction of ocean life, but the state extended their lifespans to 2023 for grid reliability. (See OTC Plants to Remain Open, Calif. Water Board Rules.)
Continued reliance on the plants could extend their lifespans beyond the retirement dates, critics of the trailer bills said. The U.S. Department of Energy retains authority over Diablo Canyon, but Newsom’s office has petitioned it for a share of federal funds to keep the plant operating, and the bills would set aside $75 million toward that goal.
The measures also enact sweeping changes to approvals of new energy projects by creating an “opt-in” process to allow the California Energy Commission (CEC) to consolidate permitting, including for larger solar arrays and battery installations, while mostly bypassing other federal, state and local permitting processes. The typically laborious review under the California Environmental Quality Act will also be streamlined.
In a joint statement, environmental groups urged lawmakers to take more time to fix the bills, which they said give “unprecedented new authority and a blanket exemption for the Department of Water Resources to finance, construct and/or operate any type of energy project without compliance with existing local, state or federal laws.”
The Nature Conservancy, Sierra Club and two dozen other groups also protested the creation of a new approval process at the CEC that “completely overrides the jurisdiction” of state, regional and local planning authorities.
During Wednesday night’s floor debate, Democratic lawmakers, including some staunch environmentalists, defended the bills as necessary for maintaining reliability over the next several years as the state transitions toward 100% clean energy.
“We’ve looked at the data, and we realize that we’re going to have or may have a shortfall,” State Sen. BobWieckowski (D) said. “It may happen this summer. It may happen in 2023, 2024 [or] 2025. … It may mean in order to keep the lights on [for the residents] of California, we may have to procure some of these dirty fossil fuels.”
After energy emergencies the past two summers, including rolling blackouts in August 2020, the state has struggled to bolster capacity to meet peak demand. Extreme heat, drought and wildfires have made that difficult, and state energy planners have said the state could face more shortfalls during the next four summers of 1,700 to 10,000 MW, depending on the severity of circumstances. (See Heat, Fire and Supply Chain Woes Threaten Calif. Reliability.)
Lawmakers previously accepted Newsom’s broad energy plan in principle but left spending details to be worked out in closed-door negotiations between the governor’s office and legislative leaders in recent weeks. (See Calif. Lawmakers Offer Alternative Energy Budget.) The result was the language in the budget trailer bills approved Thursday.
Balancing authorities in three of the four Midwest Reliability Organization subregions are likely to face capacity shortfalls this summer requiring external energy assistance or other emergency measures, the regional entity warned in its Regional Summer Assessment.
MRO conducts its regional assessment each year as a complement to NERC’s Summer Reliability Assessment and to identify potential issues on a “more granular” level, MRO Principal Reliability Assessments Engineer Salva Andiappan said in a webinar on Thursday. The RE’s assessments also analyze historical data from previous summers to spot trends that could impact grid reliability in coming seasons.
MRO’s summer forecast includes the months of June through September. Like NERC’s summer assessment, released in May, MRO warned that SPP and Saskatchewan Power are both at elevated risk of energy emergencies, while the MISO North and Central areas are at high risk. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.) Only Manitoba Hydro indicated it possesses sufficient resources to meet the subregion’s reserve margin requirements under both normal and extreme demand scenarios.
Highest Risk for MISO North, Central
The normal demand scenario, also called the 50/50 scenario, represents a prediction with a 50% chance of being exceeded, while the extreme scenario, also called 90/10, has a 10% chance of being exceeded. Under the first, MISO, SPC and SPP anticipate reserve margins of 3.2%, 2.6% and 12.3% respectively, well below the requirements of 17.9%, 11% and 16%.
Under extreme conditions, the margins for all three drop below zero, leading to a high risk that the BAs will have to issue energy emergency alerts and implement operating mitigations including non-firm imports, demand response and short-term load interruption, a likelihood that is low for Manitoba Hydro in both conditions.
MISO’s projection is based on results of the RTO’s recent Planning Resource Auction, which MRO said indicated “insufficient capacity to cover anticipated summer peak demand and increased risk of needing to implement temporary, controlled load sheds” under extreme conditions. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) The RTO’s shortfall of more than 1.2 GW was caused by increased load forecast coupled with retirements of existing generation resources and their replacement with new resources with lower capacity.
MRO 2022 summer peak capacity by fuel types | MRO
One bright spot in this forecast is that some units that “did not qualify for reserve capacity in the PRA” might still be able to help MISO serve energy during the summer. However, MRO still said the shortfall in the month of July could reach as high as 5 GW.
SaskPower, meanwhile, is expected to strain under a 7.5% increase in peak demand driven by “the economy returning to pre-pandemic levels” as well as oil and gas development. The subregion should be able to meet normal demand but may need “external assistance” in conditions of above-normal generator outages; this is also the case for SPP, where the elevated risk is attributed to drought conditions affecting water sources needed for generation and cooling.
For Manitoba Hydro, on the other hand, the scenario is quite rosy; the subregion reported it anticipates no unexpected rises in load, unlike last summer, while new generating units coming online at the Keeyask hydroelectric station are expected to expand the margin comfortably. The fifth and sixth units are expected to enter service this summer, and the last should be online by winter, MRO said.
