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November 1, 2024

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TransWest Express to Join CAISO as Tx Owner

The CAISO Board of Governors voted Thursday to admit a merchant transmission project that plans to bring Wyoming wind to California as a participating transmission owner using a new subscriber model.

The admission of the TransWest Express is still “somewhat conditional,” requiring additional steps to complete, including signing up buyers in CAISO for the line’s wind energy, Neil Millar, vice president of infrastructure and operations planning, wrote in a memo to the board.

Assuming that happens, the project will expand CAISO’s reach hundreds of miles east and establish a new transmission-owner model, Deb Le Vine, CAISO director of infrastructure contracts and management, told the governors in Thursday’s board meeting.

“This is a unique opportunity that the ISO has to expand our grid and the way that participating transmission owners come into the ISO,” Le Vine said. “The uniqueness is that TransWest Express has already gone through a public solicitation and sold the rights to its transmission lines from Wyoming to California, and then they’ll be looking for off-takers for that wind generation — about 3,000 MW of wind that they’re looking at bringing in.”

Last year, TransWest conducted a FERC-approved open-solicitation process that offered firm, long-term transmission service to California via Utah and Nevada. It decided to allocate 100% of its capacity to Power Company of Wyoming, owner of a 3,000-MW wind farm being constructed in the south-central part of the state. FERC approved the arrangement in February.

Both TransWest and Power Company are wholly owned affiliates of The Anschutz Corp., a privately held company based in Denver and controlled by billionaire Phillip Anschutz, who made much of his fortune from fossil fuels and is now seeking to benefit from California’s clean energy mandate, which requires 100% of retail energy to be carbon-free by 2045.

To meet the 2045 goal, the state will need to import as much as 10 GW of out-of-state wind by 2040, at least half of it from Wyoming, according to projections by the California Public Utilities Commission and the California Energy Commission.

CAISO’s recent 20-year transmission outlook examined new transmission needed for the undertaking, predicting overall costs of $30 billion that includes $12 billion to carry wind from the Great Plains and Rocky Mountain states. (See CAISO Sees $30B Need for Tx Development.)

TransWest applied to join CAISO in July, saying in its application that it “intends to place under the CAISO’s operational control all of [its] project transmission lines and associated facilities … that will connect to the existing bulk power system in Wyoming and Utah as well as directly to the [CAISO]-controlled grid in Nevada.”

It would be CAISO’s first subscriber participating transmission owner (SPTO), a new model that would give the ISO control of power lines without increasing the ISO’s transmission access charge (TAC), currently more than $16/MWh. Some Western entities raised concerns about the SPTO model and asked that it be vetted in a stakeholder process, but CAISO chose to move ahead with the plan. (See TransWest Express Seeks to Join CAISO.)

Once built, TransWest will consist of 732 miles of transmission lines in three linked segments: a 405-mile, 3,000-MW HVDC system between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada. It will connect in Utah to lines serving the Los Angeles Department of Water and Power (LADWP) and in Nevada to CAISO’s grid and balancing authority area.

The project is in an “advanced stage of development, focused on pre-construction matters including tower design and testing; interconnections; contracting with engineering, procurement and construction contractors; and financing,” the application said. “All major permits have been acquired, and 100% of the easements/authorizations to build on private lands have been secured.” Major parts of the project could be in service by 2026, it said.

Just before Thursday’s vote, TransWest Express COO Roxane Perruso thanked the ISO management team for “working with us on our application to become a participating transmission owner and the innovative subscriber PTO model. We think that this is a win-win for everyone … [that] avoids the need for a 39th balancing authority in the West and … particularly a generation-only BA.”

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NYISO Capacity Accreditation Implementation Worries Stakeholders

RENSSELAER, N.Y. — NYISO stakeholders last week expressed reluctance to approve the ISO’s proposed implementation of its new capacity accreditation construct, with some saying they did not fully understand all of the changes and others saying it would be applied unequally.

The proposed revisions include the implementation details and technical specifications necessary for establishing capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs), such as updated calculations for translation factors, demand curves and resource-specific derating factors.

Although the proposed revisions were ultimately approved, several stakeholders at the Business Issues Committee meeting Wednesday opposed the motions emphatically.

Jay Goodman, an attorney with Couch White, said his clients don’t oppose the capacity accreditation project outright but are “concerned with committing to implement it by May 1, 2024,” because it “will not be applied equally and accurately to all capacity providers at that time.”

Goodman said that they “perceive the capacity accreditation process as a work in progress” and that “numerous outstanding issues should be addressed or resolved prior to this vote taking place.”

They are also concerned that all thermal units will be treated as a single CARC, despite them having a “diversity of operating characteristics,” he said.

Daymark Energy Advisors CEO Marc Montalvo, representing the Utility Intervention Unit, explained that his abstention was “not because of a lack of faith in the ISO or the quality of their work” but “as much as a timing issue,” as well as a “feeling that [stakeholders] do not yet have a complete understanding of all the moving parts.”

Adam Evans, a staffer at the New York Department of Public Service, asked that “if there is remaining work that needs to done, then why would it not be included in what folks are voting on today?”

Doreen Saia, an attorney with Greenberg Traurig, recommended that NYISO edit the motion to avoid this “devolving into conversation about project prioritization” and alleviate concerns raised by stakeholders.

With guidance from Saia, NYISO then edited the motion recommending approval by the Management Committee and Board of Directors to say that the ISO is committed to addressing the capacity accreditation work plan as presented and any associated enhancements as necessary.

The proposed revisions now go to the MC this Wednesday. NYISO anticipates filing the summary of the final capacity accreditation implementation details with FERC within 90 days of MC approval.

Aggregated Hybrid Storage

The BIC also voted to recommend that the MC approve NYISO’s proposed tariff modifications that support the market participation of aggregated hybrid storage resources (HSR), generators co-located with storage resources that are all behind a single point of injection.

The changes would incentivize developers to couple generators with storage resources and, also, update the co-located storage resources (CSR) to allow for additional use cases, such as limited run-of-river hydro or landfill gas.

NYISO is targeting the third quarter of 2023 to file tariff modifications with FERC, anticipates making necessary software design updates throughout 2023 and plans on fully implementing the changes in 2025.

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FERC, NERC See Progress on Winter Weatherization

FERC Chairman Richard Glick said Thursday that regulators and industry have made “remarkable” progress on recommendations in response to the February 2021 winter storm but that he isn’t ready to declare “Mission Accomplished.”

FERC and NERC staffers told the commission during a presentation at the monthly open meeting that progress has been made on all 28 recommendations in the FERC-NERC report issued in November 2021, thanks to efforts by the ERO, Texas Railroad Commission (RRC), North American Energy Standards Board (NAESB) and National Association of Regulatory Utility Commissioners (NARUC), as well as ERCOT, MISO and SPP.

Among the responses cited by David Huff, of FERC’s Office of Electric Reliability, and Kiel Lyons, of NERC, were:

  • ERCOT’s inclusion of the February 2021 extreme winter weather conditions in calculating its base peak demand forecast for its 2022/23 Winter Seasonal Assessment; SPP incorporating a 90-10 load forecast and including limited fuel supply scenarios in its 2022/23 Winter Assessment; and MISO’s move to a seasonal capacity construct in winter 2023/24.
  • the Public Utility Commission of Texas’ work with the RRC to adopt an electric supply chain map of critical interdependent natural gas and electric infrastructure, which identify types of natural gas infrastructure to prioritize for protection from firm load sheds.
  • the PUC’s actions advancing new transmission beyond the Texas Interconnection’s current 1,220 MW of asynchronous DC ties to SPP (820 MW) and Mexico (400 MW). Southern Cross Transmission would provide a 2,000-MW link between the Texas Interconnection and the SERC Reliability region, while Grid United’s Pecos West project would add a 1,500-MW HVDC line between ERCOT’s West Texas region and El Paso in WECC territory (Project 53758). (See ERCOT Board Gives Southern Cross Project a Boost.) The FERC-NERC report said such links would increase the region’s import capacity during emergencies and improve its black start capabilities.
  • NERC’s September 2022 cold weather preparations alert and the ERO’s cold weather preparedness webinars and workshops, and the incorporation of more comprehensive extreme weather scenarios and energy assessments in NERC’s 2022/23 Winter Reliability Assessment. NERC’s Reliability and Security Technical Committee will hold a summit Jan. 31-Feb. 2 on the progress made toward implementing the recommendations.

Fourth Winter Event in 10 Years

The storm marked the largest firm load shed event in U.S. history, at 23,418 MW, and was the fourth event in 10 years in which reliability was jeopardized by unplanned generating unit outages in cold weather.

NERC initiated Project 2019-06 in response to a January 2018 cold weather event, when below-average temperatures resulted in 183 generating units in SPP, MISO, the Tennessee Valley Authority and SERC experiencing either an outage or a failure to start over a five-day period.

FERC NERC Uri Recommendations (FERC-NERC) Content.jpgFERC/NERC

 

The rules — which require generator owners (GOs) to protect their units from freezing, and transmission operators (TOPs) and balancing authorities to revise their emergency operating plans — were approved by FERC in August 2021, several months after the February 2021 storm. (See FERC Approves Cold Weather Standards.) They don’t become effective until April 1, 2023 — too late for this winter.

Glick recalled that he and NERC CEO Jim Robb vowed that the findings on the storm would result in significant change and not “gather dust” like prior reports. (See FERC, NERC Release Final Texas Storm Report.)

“I think it’s remarkable when you think about the short time period [since the report] that we’ve made progress on all 28 recommendations,” Glick said. “Now, I want to make it clear: We’re not hanging the ‘Mission Accomplished’ banner.  There’s still a lot more that needs to be done here … before we can feel more comfortable about where we stand in terms of Texas, but also elsewhere, in terms of preparedness for significant winter storms.”

‘Heavy Lift’

In late October, NERC filed for FERC approval of new reliability standards concerning freeze protection for generation and natural gas facilities impacting the bulk power system (RD23-1).

NERC said proposed reliability standards — EOP-012-1 (Extreme Cold Weather Preparedness and Operations) and EOP-011-3 (Emergency Operations) — build on the first round of cold weather standards approved by FERC in 2021, creating “a more comprehensive framework of requirements” on generator preparedness for cold weather operations and requiring TOPs to minimize the use of manual load sheds that could exacerbate emergency conditions and threaten reliability.

The report prompted Project 2021-07 (Extreme Cold Weather Grid Operations, Preparedness, and Coordination), which broke the recommendations into two phases, tackling four of them in the standards approved by NERC’s Board of Trustees in October and pending FERC approval. (See NERC Board Approves New Cold Weather Standards.)

SPP attorney Matthew Harward, the head of the standards drafting team, provided an update on the project at the Standards Committee meeting Dec. 13.

The recommendations in the second phase “are basically further identification of cold weather critical components and systems, and then the implementation of freeze-protection measures on each of those elements identified,” Harward said. “Those are GO requirements, and additional GO requirements that will be in the standard are that they must account for the effects of precipitation and wind when determining their lowest temperature [at which they are] able to operate.

“There are quite a few that will impact the BA and the data specifications between the BA, the RC [reliability coordinator], the TOP and the GO. A big one of that is that BA operating plans will need to prohibit critical natural gas infrastructure loads from participating in demand response programs,” he added.

The BAs, TOPs, RCs and transmission providers also will have new rules concerning how critical natural gas infrastructure is involved in manual and automatic load shedding.

“So we have some heavy lifts that the team is dealing with. We have a lot of participation from industry … which we feel is a good thing, but it also makes up for a lot of conversation; there’s a lot of opinions out there.”

Harward said his team is confident it can complete phase 2 and make its recommendations to the board by Sept. 30, 2023.

“It’s going to be a little more challenging than maybe we initially thought, but we are definitely up for the challenge,” he said.

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Solar Industry Challenged by NY Home Rule

ALBANY, N.Y. —  New York’s upstate/downstate power dynamic and its home rule tradition are creating siting challenges for solar developers, speakers told the New York Solar Energy Industries Association’s 2022 Solar Summit last week.

To Betta Broad of New Yorkers for Clean Power, New York’s strong home-rule tradition is a double-edged sword. It was central to the strategy to block hydraulic fracturing in the state, she said, but now is being used to block renewable projects.

“In [the fracking battle], home rule was really our friend,” Broad said. “But now here we are facing a lot of issues related to home rule that don’t necessarily help us scale up solar and renewables the way that we want to.”

The majority of New Yorkers do not even know about the climate mandates contained in the Climate Leadership and Community Protection Act (CLCPA), she said.

Mark Richardson of U.S. Light Energy said local opposition to solar — which ranges from Not In My Back Yard absolutism to infrastructure concerns — has led local governments to adopt creative blocking strategies such as restrictive zoning, domestic manufacturing requirements and untenable setback zones.

The state did weaken home-rule power over solar projects with passage of the Section 94-C law in 2020 and with creation of the Office of Renewable Energy Siting, he said. But 94-C and ORES are not cure-alls, and they do not apply to projects smaller than 25 MW, he said.

Genevieve Trigg, who represents project developers for the law firm Barclay Damon, summarized the top three challenges to siting solar in New York: the roadblocks in the local review process and the amount of time they consume; the cost uncertainty of project development, with no standard figure for the host benefit fees that municipalities are demanding; and the inherent conflict between home rule and the CLCPA, which sets statewide policy.

“I’m in the thick of this on a daily basis,” Trigg said. “We have seen some tremendous progress in the last five years in the solar industry, but it seems that a lot of our developer clients are still facing a tremendous amount of opposition and various challenges.”

She did not bother offering anecdotes.

“I think if you ask any developer in the room they have their own set of horror stories,” Trigg said.

The issue of “two New Yorks” also came up. Upstate regions already are running mostly on emissions-free electricity and downstate relies mostly on fossil-generated power. The state’s top elected officials — all Democrats and mostly downstaters — are counting on massive solar arrays and onshore wind farms built upstate to power the downstate region. This has sparked some pushback upstate, particularly outside its cities.

Assemblymember Patricia Fahy, a Democrat from the capital city, told the audience she felt like she needed to duck when the topic turned to solar power during a farm tour this past summer.

“We live in the most divided of times,” she said.

Fahy, a strong proponent of climate protection and decarbonization, did not offer much hope for quick improvement on this front, saying home rule is a cherished tradition in New York.

“All of this is a full-employment policy for lawyers,” she said. “But we will have to continue to legislate because we have these goals. … I know at times these do seem rather insurmountable, but it is those examples that we hope to learn from as we work to streamline these systems.”

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Counterflow: A Few of My Favorite Things

What makes us happy? In this holiday season I thought I would take a break from our industry and throw out a few points of joy for me (besides family and friends). And if you want to nominate some, please email me at huntoon@comcast.net for a potential sequel.

  1. No Surrender festival. Crazy Springsteen sing-along and play-along with 4,000 delirious Spaniards.  https://www.youtube.com/watch?v=alorNxGo0FM
  2. The final scene of “Casablanca.” The triumph of good over evil, the sacrifice of love for the cause, the friendship you didn’t see coming, and written on the fly during war. In two parts: https://www.youtube.com/watch?v=rEWaqUVac3M and https://www.youtube.com/watch?v=5kiNJcDG4E0.
  3. “The Joke” by Brandi Carlile. It gets me every time. https://www.youtube.com/watch?v=5r6A2NexF88
  4. Anthony Bourdain. I’m still not sure what it was he had, but he had it in spades.
  5. “Vacation” by the Go-Go’s. Faux surfing starts at 1:15. https://www.youtube.com/watch?v=2RHTiXvELNg
  6. “Star Trek: The Next Generation.” Of course the original series was great, but almost every episode of the Picard series is too.
  7. Frosty the inflatable. Every year our 8-foot Frosty goes up on our second-floor deck happily welcoming everyone. There’s just something about that.
  8. “The Rocky Horror Picture Show.” How did Richard O’Brien create all this 47 years ago? My favorite song, “Science Fiction/Double Feature” (not “Time Warp”). https://www.youtube.com/watch?v=GKhPVHoodrU
  9. “I’d Do Anything for Love (But I Won’t Do That).” Mr. Loaf may have learned a little about drama from his cameo for Mr. O’Brien as a leather-clad biker. https://www.youtube.com/watch?v=9X_ViIPA-Gc
  10. The beach. Any beach.

The best of the holidays to you and yours!

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

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NERC Board Member Argues for Increased Authority

NERC Trustee Sue Kelly urged Standards Committee members last week to support giving the Board of Trustees the authority to issue standards when it sees inadequate progress on an urgent reliability issue.

In a year-end briefing to the committee Dec. 13, Kelly said the board is seeking to “address the increasing disconnect between the pace of industry change and the more deliberative pace of NERC’s processes — which seems to becoming increasingly apparent — without adversely impacting the key role of industry in our work.”

Kelly said the board will be considering “big issues” in 2023, including an expansion of registration requirements and re-examining the definition of the bulk electric system.

She also expressed support for a proposal to add a new Rule 322 to NERC’s Rules of Procedure to allow the board to issue standards on an “urgent and extraordinary” reliability issue. “Right now, only FERC has that authority,” under Rule 321 of the RoP, said Kelly, the board’s liaison to the committee.

Proposed Section 322 (NERC) Content.jpgProposed Section 322 | NERC

The Standards Process Stakeholder Engagement Group, which proposed the new rule in October, noted that FERC has never invoked Rule 321. “The SPSEG believes that new proposed Rule 322 also should not need to be used, but believes that the rule must be in place to enable NERC meet its [Federal Power Act] Section 215 responsibilities in extraordinary circumstances.”

Kelly said the board is revising its proposal to address concerns expressed at the November meeting of the Member Representatives Committee. The revised package will be posted in early January for stakeholder feedback.

She quoted Trustee Roy Thilly, who said, “‘The proposed directive authority would be limited to extraordinary circumstances, and the board would be required to provide notice of our reasons for preliminarily concluding that a directive is necessary under the circumstances. Stakeholders would have the opportunity to comment on this notice before the board might take any action.’

“So, we built in a lot of process and comment opportunities here,” Kelly added. “Even after the board does take such action, industry would be responsible for drafting the standard. Only if the drafting and balloting process fails would staff then prepare a draft standard for the board’s review.”

Personal Observations

Kelly, the former CEO of the American Public Power Association, then offered what she called her “personal” observations, noting that NERC standards are developed by technical experts.

“They are not an off-the-shelf product by any means. We all understand this, but the outside world does not understand this,” she said. “And I am concerned by some of the recent public comments on our standards process. At FERC’s supply chain technical conference just last week, it was again noted that NERC takes a long time to develop and implement standards. We need to know that those views are out there, whether we agree with them or not, or if we think that time is justified or not. You know, perception can be reality.” (See FERC-DOE Technical Conference Considers New Standards for Supply Chain Threats.)

Kelly said those perceptions are one reason why the board needs the “fail-safe authority.”

“The authority supports NERC’s foundational ability to address urgent reliability issues under our self-regulatory model without FERC having to order NERC to do it. I honestly believe that this authority would very rarely, if ever, be used. But having it in the rules would give NERC the ability to carry out its standard setting responsibilities … if the standards process looks like it otherwise will clearly fail. So, I’m going to conclude by saying we need to collectively show the wider world why our unique regulatory model remains the best one for this industry.”

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Stakeholders Respond to ERCOT Market’s Proposed Redesign

Texas regulators have received almost 120 comments from ERCOT stakeholders and the public about their proposed market redesign, feedback they will review and discuss before turning over their final recommendation to lawmakers next year.

From global energy powerhouses like Shell Energy, to individual ratepayers, commentators have given the Public Utility Commission hundreds of pages for their holiday reading pleasure. Stakeholders had 35 days to file their comments before a Thursday deadline (54335).

The comments echo those made by lawmakers during recent public hearings: The PUC’s preferred market design is too complicated and an unknown among other grid operators. There is no reliability standard. It won’t attract new baseload generation to Texas.

A San Francisco-based energy consulting firm spent several months modeling and analyzing market designs proposed by the PUC following public work sessions after the deadly 2021 winter storm nearly collapsed the ERCOT grid. Energy + Environmental Economics (E3) recommended a forward reliability market construct that relies upon a centrally cleared auction procuring the “requisite” amount of reliability credits.

PUC staff instead urged the commissioners to pursue a performance credit mechanism (PCM) that requires load-serving entities to buy performance-based credits from generation resources in a voluntary forward market. The credits are awarded to resources through a retrospective settlement process based on availability during the 30 hours of highest risk, according to their load-ratio shares during those same periods. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

Potomac Economics, ERCOT’s Independent Market Monitor, said it found the PUC’s first phase of market changes to be “far more effective and more sound economically” than the proposals in E3’s report. The early modifications included a 44% reduction in the market’s price cap to $5,000/kWh and shifting the operating reserve demand curve (ORDC) so that the market’s shortage-pricing mechanism increased real-time energy revenues by $1.7 billion this year through November, according to Potomac.

“We continue to believe in the effectiveness of the energy-only market,” the Monitor wrote. “The energy-only market is an effective pay-for-performance mechanism and should be retained in full without adding an unnecessary separate availability payment structure that would be difficult to accurately hedge or predict due to its ex post procurement.”

Potomac recommended against the PUC moving forward with any of its designs, saying the PCM is “a less effective and efficient means to facilitate performance by ERCOT’s generation fleet” than the current construct. It did allow that the PCM would be “less disruptive” to the current market than the backstop reliability service (BRS) mechanism, an ancillary service meeting specific reliability needs during high uncertainty periods.

ERCOT Market Reorm Assessment (E3) Content.jpgERCOT market participants have plenty to say about a consultant’s report on the ERCOT market’s redesign. | E3

The Steering Committee of Cities Served by Oncor wrote that the PUC’s ultimate goals and principles in redesigning the market remain “unclear.” It called on the commission to direct E3 to revise and expand its analysis, saying the firm’s report is “inadequate as a basis for such a momentous redirection of the state’s and consumers’ energy resources.”

The Texas Public Policy Foundation, a nonprofit organization pushing the oil and gas industries’ interests, took aim at the “overinvestment” in renewable energy, saying any new market design needs to also address “underinvestment” in dispatchable generation.

“Any program that only addresses the underinvestment problem is simply countering the federal subsidies for wind and solar with state subsidies for dispatchable generation and will lead to skyrocketing costs for ratepayers,” the foundation said.

The PCM also has its supporters. Vistra and NRG Energy, the state’s two largest generation owners, favored the PUC’s recommendation.

The R Street Institute — a nonpartisan, public policy research organization that last year pushed its own version of the PCM — called the PUC’s preferred design a “workable framework” that will add “additional incentives for installed [reserve] capacity.”

The Texas Competitive Power Advocates (TCPA) — a trade association representing generators, wholesale marketers and retail providers — said it stands ready to bring more than 4.5 GW of additional generation to ERCOT if the PCM is adopted under the “right framework.”

“The E3 report demonstrates that the status quo energy-only market will not incentivize sufficient new generation or retain sufficient existing generation to ensure resource adequacy and reliability outcomes acceptable to Texans,” TCPA Executive Director Michele Richmond wrote. She said the PCM will meet the objectives of legislation passed year that requires a reliability standard for the grid and a market design ensuring reliability during extreme weather and periods of low non-dispatchable power.

“The [PCM] can achieve this; alternative and unstudied half-measures cannot,” Richmond said. “Nor can state-subsidized generation or loan programs, which may marginally reduce the cost of new generation but would also accelerate the retirement of the gas generation that kept the power on this summer.”

The PUC has scheduled a work session on Jan. 12 to discuss the design proposals and stakeholder feedback. A vote is not expected on the proposals during that meeting, but a plan is expected to be adopted later in the month, a commission spokesperson said.

“As [PUC Chair Peter Lake] has repeatedly assured, the commission will continue to work closely with the legislature on this important issue,” Rich Parsons said in an email to RTO Insider.

ERCOT’s Kenan Ögelman, vice president of commercial operations, said it will take at least 1.5 to 2.5 years and up to $4 million to implement the PCM, assuming the project can be done concurrently with the delayed real-time co-optimization (RTC) market tool’s development. He said that estimate is in addition to at least six months to write the necessary rules and protocols.

In comparison, delivering the BRS will take between 15 months and 2.5 years, Ögelman said. Again, this assumes the design’s work will be managed alongside that of the RTC tool. (See ERCOT Technical Advisory Committee Briefs: Dec. 5, 2022.)

“There is significant overlap in the systems that would be impacted by implementation of PCM and BRS, as well as the employees who would be needed to work on those projects,” Ögelman wrote. “As such, a decision to implement one program would significantly impact the timing of when the second program could be delivered.”

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CAISO, WEIM Boards Back Reliability Enhancements

The CAISO Board of Governors and the Western Energy Imbalance Market Governing Body on Wednesday adopted storage and resource-sufficiency upgrades intended to promote grid reliability.

Exercising joint authority on WEIM matters, both boards approved changes to the interstate market’s resource sufficiency evaluation (RSE). The test is meant to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

The two bodies adopted a first phase of changes to the RSE in February. Scheduled to take effect this summer, they include provisions to measure a participant’s available supply more accurately and allow demand response programs to count toward the RSE. (See CAISO, WEIM Adopt Resource Sufficiency Changes.)

The second phase of changes approved Wednesday will allow transfers into balancing authority areas that failed the RSE, subject to surcharges.

“These optional transfers, termed ‘WEIM assistance energy,’ will enable BAAs that are short supply to access the WEIM’s efficient dispatch while still providing incentives for BAAs to participate in the WEIM with sufficient resource to meet their own load,” Anna McKenna, CAISO’s vice president of market policy and performance, wrote in a Dec. 7 memo to the ISO and EIM boards.

Market participants helped develop the changes through CAISO’s RSE enhancements stakeholder initiative. NV Energy (NYSE:BRK.A), for example, raised concerns in February about the RSE being too restrictive and reducing the market’s ability to help in potential energy emergencies, which Nevada and California have faced in summer heat waves the past three years.

The utility asked CAISO to develop a mechanism to allow excess supply to “be available to the distressed EIM entity at an appropriate scarcity price,” Market Policy Manger Lindsey Schlekeway wrote in a Dec. 14 letter to the boards.

“NV Energy supports the CAISO’s final proposal for the resource sufficiency enhancements phase 2 because it creates a financial mechanism that EIM entities can opt in to,” Schlekeway wrote. “We recognize this is not a final solution for the resource sufficiency enhancements, but it is of critical importance not to delay the implementation of this reliability enhancement past the summer of 2023 for grid reliability.”

The ISO’s Market Surveillance Committee (MSC) said in a written opinion that the change will likely produce mixed results, “but we understand that the one or two BAAs that may utilize it believe it will be beneficial. However, it is our belief that these changes still leave the RSE almost certainly in need of further refinement.”

Another change exempted CAISO from counting low-priority exports in its RSE obligations.

“This change accounts for interactions between WEIM energy transfers and ISO exports that can occur in the real-time markets and can result in [CAISO] erroneously failing the RSE when it has sufficient internal supply resources to meet its load obligations,” McKenna wrote. “WEIM BAAs receiving these exports would still be permitted to count the supported supply towards meeting their RSE obligations.”

The MSC supported the change as “it clearly constitutes improvements in the RSE relative to current practice.”

Storage Enhancements

Additional reliability enhancements approved Wednesday are meant to better manage an increasing amount of battery storage in CAISO and the WEIM.

The ISO’s energy storage enhancements stakeholder initiative, begun in February 2021, generated the proposals. California and WEIM participants in the Southwest need battery backup power as solar ramps down late in the afternoon but demand remains high in heat waves from air conditioning use.

CAISO has been adding battery storage rapidly since the rolling blackouts of summer 2020, when it had only 200 MW, and it now has 4,700 MW online, with a goal to add 10 GW or more. Other WEIM entities are expected to add significant amounts of storage in coming years.

The ISO’s relatively recent experience with battery storage has led it to make corrections and adjustments, which it expects to continue as it moves forward.

“Most of the storage policy and the market tools that we’re using on the system today were implemented at a time before we had very much storage capacity actually operating and performing,” Gabriel Murtaugh, the ISO’s storage sector manager, said in Wednesday’s meeting. “So, this policy really is the ISO looking back on performance of these resources over the last few years and thinking about where we need to go and how we need to evolve.”

The grid reliability enhancements include software tools to better account for a storage resource’s state of charge when the resource is providing regulation service, requiring it to quickly charge or discharge to meet grid needs. In a September heat wave that brought CAISO close to ordering blackouts, some batteries discharged early and were not available when needed most.

A second component of the effort establishes new bidding requirements for storage resources that provide ancillary services. It requires “scheduling coordinators for storage resources to submit economic energy bids to charge when awarded upward ancillary services, or economic bids to discharge when providing regulation down,” McKenna wrote. “This, coupled with the first change, will ensure that a storage resource is available to provide awarded ancillary services.”

McKenna noted some stakeholders — particularly Vistra (NYSE:VST), a major operator of utility-scale battery storage in California — had expressed concern about the new bidding requirements “potentially reduc[ing] how much ancillary services storage resources may be awarded, which could impact resource profitability.”

“The ISO recognizes this limitation, [but it] has experienced operational issues during some periods in which storage resources that are scheduled to provide ancillary services may be unable to do so due to either too high or too low of state of charge,” she wrote. “This situation can threaten grid reliability if operating reserves from such resources are unable to be deployed during a contingency outage event. This typically occurs when storage resources are at very high or very low levels of state of charge and can be less responsive.”

The changes require FERC approval before they can take effect. Vistra indicated in a letter to CAISO that it might challenge the ancillary service proposals, which it said “would lead to inefficient [and] potentially harmful market outcomes in implementation if these proposals are approved by FERC.”

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Invenergy Files Suit Against Wash. Cap-and-trade Program

The owner of Washington’s only non-utility gas-fired plant has filed a suit over what it claims is discriminatory treatment in the state’s impending cap-and-trade program.

Chicago-based Invenergy on Tuesday filed the action against the program’s administrator, Washington’s Department of Ecology, in the U.S. District Court in Tacoma, Wash. 

Invenergy owns the 698-MW Grays Harbor Energy Center in Elma, Wash., the only gas-fired facility in Washington not owned by a utility. The plant did not receive an allocation of no-cost carbon allowances such as those granted to utility-owned power plants under the state’s new cap-and-trade program, which goes into effect Jan. 1.

The company’s petition contends that the state law underpinning the program, the Climate Commitment Act, is unconstitutional because it discriminates against independent owners of fossil fuel plants, violating the Equal Protection Clause of the U.S. Constitution. The lawsuit also alleges the Ecology Department denied the plant no-cost allowances under the program because it has an out-of-state owner, a violation of the Constitution’s Commerce Clause.

Invenergy complains that Grays Harbor will have to add the costs of buying cap-and-trade allowances to its power prices, a burden not faced by the 12 other utilities that own gas-fired plants. “The [Climate Commitment Act’s] allocations of no-cost allowance uniquely harm Invenergy. … Ecology brushed aside Invenergy’s concerns about unfair treatment,” the complaint said.

The lawsuit seeks no-cost allowances for the plant.

Under cap-and-trade, greenhouse gas emitters must acquire allowances for specific volumes of emissions, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions and allowances will decrease over time under the program.

The program’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first auction is set to be held at a yet-to-be-scheduled date in February 2023. The state will set the number of allowances 60 days prior to the auctions.

Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the Western Climate Initiative, which includes California and Quebec, participants would expand their purchase and trading territory to those two areas. Washington is the second state to adopt a cap-and-trade system following California.

For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.

Invenergy’s lawsuit alleges that the 12 in-state utilities have stronger local, political, donation and lobbying presences in Washington than that company, leaving the Illinois company out-gunned in efforts to lobby the state legislature and Ecology Department.

“We are reviewing the filing by Invenergy and Grays Harbor Energy,” Ecology said in a statement. “As we work to implement the Climate Commitment Act and reduce the largest sources of carbon pollution in Washington, we are committed to following the direction set by the Legislature. We believe courts will find that the law and Ecology’s work to implement it are fully constitutional.” 

Ecology rejected allocating no-cost allowances to Grays Harbor goes despite a recommendation by Washington’s Energy Facility Site Evaluation Council in September to extend the allowances to the plant.

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ERCOT Briefs: Week of Dec. 12, 2022

Texas Grid Prepared for Winter’s First Frigid Blast

ERCOT on Friday issued an operating condition notice to the system’s generators in advance of a polar blast that will drop temperatures below freezing next weekend.

The procedural notice alerts the grid operator’s market participants that temperatures will be 25 degrees Fahrenheit or lower in the Dallas and San Antonio metro areas from this Thursday through Dec. 26. It is the lowest of ERCOT’s four emergency-level communications.

ERCOT on Saturday projected demand to peak at 69.7 GW at 10 a.m. on Dec. 23, more than 2 GW more than its forecasted winter peak of 67.4 GW in its seasonal assessment released in November. (See ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand.)

“As we monitor weather conditions, we want to assure Texans that the grid is resilient and reliable,” ERCOT CEO Pablo Vegas said in a press release. “We will keep the public informed as weather conditions change throughout the coming week.”

Meteorologists have said the cold weather could threaten regional records that date back to 1983 but won’t be as bad as the deadly 2021 winter storm that almost brought down the ERCOT grid.

“The duration of this cold, the lack of snow and ice, and the intensity of the cold statewide will still lag February 2021, so at this point, we’ll take ERCOT at their word that grid conditions should be manageable,” Space City Weather meteorologist Matt Lanza said.

The Texas grid operator said it has sufficient generation to meet the forecasted demand and will continue to provide updates. The primary concern remains natural gas production, where wellheads can freeze and pipelines lose pressure. It was the lack of supplies from the gas fields that led to much of the generation problems during the 2021 storm.

ERCOT has increased weatherization requirements and improved coordination with the gas industry since the storm.

Fuel Mix Dashboard Added to Website

The grid operator has unveiled a new fuel mix dashboard on its website that provides a real-time view of energy generation by resource type.

ERCOT Fuel Mix (ERCOT) Content.jpgERCOT has added a real-time fuel mix dashboard to its website. | ERCOT

 

The dashboard offers several views of energy generation. The real-time view shows the current percentages of energy generated by resource type, with current and previous day options that can be displayed in a stack view or a line chart.

The fuel mix includes “power storage” as the output from energy storage resources when they are discharging power. Under current market rules, power consumed by storage resources when they charge is included in system load.

Dan Woodfin, vice president of system operations, said the dashboard is the “latest in a series of improvements to increase public visibility” into ERCOT.

The dashboard is accessible from the Grid and Market Conditions page on ERCOT’s website.

Brazos Repays Market $1.15B

ERCOT will begin distributing holiday gifts to market participants this Tuesday after an initial payment of $1.15 billion from Brazos Electric Power Cooperative last week. The cooperative declared Chapter 11 bankruptcy following 2021’s disastrous winter storm and only recently had a reorganization plan approved by a federal bankruptcy plan. (See Bankruptcy Judge Approves ERCOT-Brazos Settlement.)

Under the terms of a settlement agreement between ERCOT and Brazos, the cooperative will eventually pay the grid operator $1.4 billion to resolve its short pay to the market. The $1.15 billion Brazos sent to ERCOT on Thursday will be followed by 12 annual payments of $13.8 million.

In a market notice, staff told market participants the first payment will fully replenish $599.7 million for congestion revenue rights funds that they used to reduce the market shortfall, attributable to Brazos’ short-pay, immediately following the winter storm. The funds will also be used to pay eligible market participants for their allocable portion of the Brazos short-pay claim.

The timing and amount of payments to eligible market participants will be determined by the payment option they elected or were assigned.