Avangrid Seeks to Terminate Commonwealth Wind PPAs

Avangrid has moved to terminate power purchase agreements for Commonwealth Wind, a 1.2-GW offshore wind project it is developing in Massachusetts, saying the deals have become financially untenable and that the other parties refuse to renegotiate.

In the dismissal motion it submitted to the state Department of Public Utilities on Friday and in a public announcement, the company said it remains committed to Commonwealth Wind. But it said the project should be wrapped into the state’s 2023 offshore wind power solicitation, at which point Avangrid could submit a bid that would be financially sustainable and proceed on a timetable that would meet the state’s 2030 climate protection goals.

Avangrid said the bid it submitted in September 2021 and the PPAs it subsequently negotiated with three electric distribution companies (EDCs) in April 2022 were overtaken by factors including high inflation, sharply higher interest rates, the war in Ukraine and supply chain shortages.

On Oct. 20, Avangrid asked the DPU to put its review of the PPAs on hold for a month so it could renegotiate them. The three EDCs — Eversource Energy, National Grid and Unitil — opposed this, saying they had no intention of renegotiating.

Mayflower Wind Energy on Oct. 27 made a similar request to delay review of the PPAs for 400 MW of wind power it is developing off the Massachusetts coast.

The DPU denied the requests Nov. 4, saying the developers could move forward with the PPAs in place or move for dismissal, but not renegotiate them. Mayflower withdrew its request Nov. 7, saying it would continue with the PPAs and seek to resolve issues through conversation. It declined to comment Monday on its plans or the status of those talks.

But Avangrid on Nov. 14 said it would continue with the proceedings and seek ways to make Commonwealth financeable and economically viable. (See: Mass. OSW Projects to Continue Through Regulatory Process.)

On Friday, Avangrid moved for dismissal, saying the EDCs had refused to meet with it on the matter.

“No interest is advanced by approving PPAs that cannot and will not lead to the development of offshore wind energy generation,” the company’s attorneys wrote. “Instead, the commonwealth should conduct a robust fourth solicitation under Section 83C as soon as possible.”

In its public statement Friday, Avangrid emphasized its commitment to clean energy in Massachusetts, including its 800-MW Vineyard Wind I project slated to come online late next year. It said it remained committed to Commonwealth Wind and was disappointed the EDCs had refused to discuss it.

The DPU is reviewing Avangrid’s dismissal motion. Danielle Burney, spokesperson for the Massachusetts Executive Office of Energy and Environmental Affairs, which oversees DPU, said in an email that the offices of Gov. Charlie Baker and Lt. Gov. Karyn Polito were displeased with Avangrid’s move.

“The Baker-Polito administration is disappointed by Avangrid’s request to the Department of Public Utilities to dismiss the review of the Commonwealth Wind contracts,” Burney wrote. “But [the administration] remains committed to the deployment of commercial-scale offshore wind and advancing clean, affordable energy on behalf of the Commonwealth’s residents and businesses, while reducing greenhouse gas emissions and meeting the state’s emissions goals, including achieving net zero in 2050.”

December 20, 2022

PJM MRC/MC Preview: Dec. 21, 2022

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See Jan. 3’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 10: Pre-Scheduling Operations resulting from a periodic review.

C. Endorse proposed revisions to Manual 14D: Generator Operational Requirements resulting from a periodic review.

D. Endorse proposed revisions to Manual 27: Open Access Transmission Tariff Accounting resulting from a periodic review.

E. Endorse proposed clarifying tariff and Operating Agreement (OA) revisions as endorsed by the Governing Documents Enhancements and Clarifications Subcommittee (GDECS).

Endorsements (9:10-10:10)

1. Energy and Reserve Market Circuit Breaker (9:10-9:40)

Adrien Ford of Old Dominion Electric Cooperative will present the main motion for a proposed “circuit breaker”: a mechanism for limiting extremely high prices. David Scarpignato of Calpine will present an alternative motion for a proposal.

Stakeholders have expressed mixed opinions on the issue, with a poll conducted in the Energy Price Formation Senior Task Force yielding less than 50% support for each of the seven packages then under consideration. Discussion was tabled during the November MRC so that ODEC and Calpine could attempt to form a compromise package. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)

The committee will be asked to endorse a proposed solution.

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

2. Rules Related to Market Suspension (9:40-9:55)

PJM’s Stefan Starkov will review a proposal addressing the treatment of long-term market suspensions, meant to provide a solution for settling real-time market prices when they cannot be determined. (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.)

The committee will be asked to endorse the proposed solution.

Issue Tracking: Rules Related to Market Suspension

3. Market Participant Default Flexibility (9:55-10:10)

PJM’s Colleen Hicks will present a proposal to allow the RTO flexibility to allow market participants to continue operating in markets after a default under certain circumstances. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022.)

The committee will be asked to endorse a proposed solution and corresponding tariff and OA revisions.

Issue Tracking: Market Participant Default Flexibility

Members Committee

Consent Agenda (1:35-1:40)

B. Endorse proposed tariff and OA revisions supporting the transmission constraint penalty factor solutions package. (See “TCPF Adjustments Permitted for Issues with Ongoing Solution,” PJM MRC Briefs: Nov. 16, 2022.)

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

C. Endorse proposed revisions to Manual 15: Cost Development Guidelines and OA Schedule 2 addressing the development of variable operations and maintenance costs. (See “MRC Approves VOM Package,” PJM MRC Briefs: Nov. 16, 2022.)

Issue Tracking: Variable Operating and Maintenance Cost

D. Endorse proposed revisions to the tariff, Reliability Assurance Agreement (RAA) and OA to prohibit critical natural gas infrastructure load from participating in demand response programs, pursuant to the recommendations included in the FERC/NERC report on the February 2021 winter storm in the south central US. (See “Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented,” PJM MRC Briefs: Oct. 24, 2022.)

Issue Tracking: Critical Gas Infrastructure – Demand Response Participation

E. Endorse proposed corresponding tariff and OA revisions supporting the financial transmission rights Bilateral Review and Reporting solution. The changes would require that FTR bilateral agreements be reported to PJM within 48 hours of their execution, accompanied by certain data, including FTR start/end, quantity, source and price. (See “Other Committee Actions,” PJM MRC Briefs: Nov. 16, 2022.)

Issue Tracking: FTR Bilateral Transactions Review and Reporting Requirements

Endorsements (1:40-1:55)

Elections (1:40-1:55)

Michele Greening will review the proposed next year’s sector representatives for the Finance Committee, sector whips and the vice chair of the committee. The MC will be asked to elect the proposed representatives.

December 20, 2022December 27, 2023

FERC Denies Tenaska’s Complaints over Wind Curtailments

FERC on Thursday denied a Tenaska complaint alleging that several grid operators adopted operating guides that resulted in unduly discriminatory curtailment of a wind farm it owns and operates.

The commission said in its order that Tenaska failed to show unjust, unreasonable and unduly discriminatory or preferential behavior under the Federal Power Act. Because it denied the complaint, FERC also rejected Tenaska’s requested relief for $9 million in lost revenue from the alleged curtailment (EL-22-59).

Tenaska filed its complaint in May, charging that MISO, SPP, Associated Electric Cooperative Inc. (AECI) and Tennessee Valley Authority had adopted operating guides that curtailed the Clear Creek Wind Project in a manner inconsistent with their tariffs.

The 242-MW facility sits within AECI’s Missouri footprint. The cooperative is the wind farm’s sole purchaser of power.

AECI is a generation and transmission cooperative and is classified as an “unregulated transmitting utility” without a tariff on file at FERC. TVA serves as the NERC-registered reliability coordinator for AECI’s balancing authority and MISO and SPP neighbor the cooperative’s transmission system.

FERC found MISO had not treated Tenaska in an unduly discriminatory manner, noting the company did not present any evidence that MISO has curtailed the wind farm. It also pointed out that the project is not located in MISO’s footprint; that Tenaska does not take transmission service from MISO for the project; and that MISO determined that no affected system network upgrades were required for the facility to operate.

The commission ruled SPP, AECI and TVA had not treated Tenaska unreasonably, although their collective actions did result in the Clear Creek project’s curtailment. However, according to the SPP-AECI joint operating agreement and SPP’s tariff, the wind farm is subject to limited operation until SPP can complete network upgrades on its system.

“Therefore, such curtailment is permissible to manage congestion and ensure the reliable operation of the transmission system,” the commissioners wrote.

FERC noted Tenaska’s facility is subject to limited operation because it entered commercial operation before SPP was able to complete the necessary network upgrades on its system. Because of that, the commission found Tenaska is “differently situated from other interconnection customers who are not subject to limited operation.”

The commission also disagreed with Tenaska’s argument that SPP should be required to file its operating guides with FERC. It said SPP’s operating guides are the mechanism by which the Tenaska facility’s limited operation was set and do not significantly affect rates, terms or conditions of service. FERC upheld SPP’s and AECI’s request to not publicly release the guides.

Commission Accepts Late Agreements

The commission accepted four of five late agreements filed by Cheyenne Light, Fuel and Power, a subsidiary of Black Hills, effective Dec. 14, 2021 (ER22-109).

The late agreements were discovered after a comprehensive review of the utility’s effective transmission and wholesale energy contracts to ensure any jurisdictional agreements were properly filed. They included a consolidated facilities agreement, an interconnection agreement, an Air Force agreement, an operating agreement and a large generator interconnection agreement (LGIA).

FERC only rejected an LGIA with Silver Sage Windpower, which dated to 2009. The LGIA contained seven non-conforming provisions, but the utility said it did not change the fact that a transmission provider under the commission’s large generator interconnection process is only paid for its actual costs in facilitating the interconnection. That meant the Silver Sage agreement only provided for collection of pass-through costs associated with the generation’s interconnection, Cheyenne Light said.

The commission said Cheyenne Light had not demonstrated that the deviations from the pro forma LGIA are necessary to address specific reliability concerns, novel legal issues or other unique factors associated with the agreements.

December 20, 2022

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.”

December 19, 2022

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.

December 19, 2022June 14, 2023

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

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.

December 19, 2022

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.”

December 19, 2022November 29, 2023

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.

No Surrender festival. Crazy Springsteen sing-along and play-along with 4,000 delirious Spaniards. https://www.youtube.com/watch?v=alorNxGo0FM
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.
“The Joke” by Brandi Carlile. It gets me every time. https://www.youtube.com/watch?v=5r6A2NexF88
Anthony Bourdain. I’m still not sure what it was he had, but he had it in spades.
“Vacation” by the Go-Go’s. Faux surfing starts at 1:15. https://www.youtube.com/watch?v=2RHTiXvELNg
“Star Trek: The Next Generation.” Of course the original series was great, but almost every episode of the Picard series is too.
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.
“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
“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
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.

December 18, 2022December 31, 2023

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

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.”

December 18, 2022June 14, 2023

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.jpg

ERCOT 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.”