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July 31, 2024

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BOEM Approves Coastal Virginia Offshore Wind

Federal regulators have approved the nation’s fifth and so far largest utility-scale offshore wind farm: the 2.6-GW Coastal Virginia Offshore Wind project. 

Dominion Energy has been gathering components in anticipation of the Record of Decision that the U.S. Bureau of Ocean Energy Management issued Tuesday. Dominion said it plans to start construction in late 2023 and complete the work in late 2026. 

The project is an integral part of the company’s move toward clean energy, it said. 

“More than a decade of work has gone into the development, design and permitting of CVOW,” Dominion CEO Robert Blue said in a prepared statement. “Offshore wind is a vital part of our strategy to provide our customers with a diverse fuel mix that delivers reliable, affordable and increasingly clean energy.” 

The project will entail up to 176 wind turbine generators rated at 14.7 MW each. The layout of the offshore infrastructure was modified from initial proposals to reduce impacts on fisheries and ocean navigation, based on input BOEM received during public comment periods. 

The Record of Decision includes provisions to avoid impacts from construction and operation. BOEM said Dominion has committed to fishery mitigation funds to compensate the commercial and recreational fishing industries for any losses inflicted by CVOW. It also will take steps to reduce the chances of harm to protected ocean species. 

The decision comes 10 years and two months after Dominion won Lease Area OCS-0483 in a BOEM auction. The 112,799-acre zone stands 23.5 nautical miles east of Virginia Beach. 

Dominion has been laying the groundwork for the project even as it worked its way through the review process. It reached a milestone Oct. 27, when the first eight monopile foundations were offloaded at the Portsmouth Marine Terminal. The massive steel cylinders will be stored there to await installation, which is anticipated in spring 2024. 

More than 750 workers have been involved in the project directly or indirectly as Dominion ramped up preparations for CVOW, most of them in the Hampton Roads region. The company said more than 1,000 workers will support the project’s operations and maintenance after construction is complete. 

CVOW is the fifth commercial-scale project approved by BOEM, which previously greenlit the Vineyard Wind 1, South Fork Wind, Ocean Wind 1 and Revolution Wind projects. 

But in another way, CVOW was first: Dominion installed two 6-MW turbines in the lease area for research purposes. When they went online in fall 2020, they provided the first grid-connected wind power in U.S. federal waters. (Rhode Island’s Block Island Wind Farm went online in 2016 but is in state waters.) 

Wind power development off the Northeast coast has run into serious financial problems. Two major New England projects have canceled their power purchase agreements, and a third is in the process of doing so. Three major projects are at substantial risk of dropping out of New York’s development queue. 

The problem in each case is that the developers locked in their revenue before they locked in their construction costs, then were socked by inflation and rising interest rates. 

By contrast, construction is well underway on the first two projects, Vineyard and South Fork. CVOW seems to be in the same position: able to proceed to construction now because it locked in its costs early enough. 

In a Sept. 5 news release, Blue credited Virginia lawmakers and regulators with creating a framework that allowed it to take those steps. 

“[The framework] enabled us to take a differentiated approach to project development, securing agreements early with offshore wind suppliers for material and services while giving them confidence in our project’s completion,” Blue said. “This allows our vendors to maintain focus on delivering their equipment and services on time. Not only is our project on budget and on schedule, but it is also estimated to deliver electricity at a levelized cost that competes very favorably with the nation’s unregulated offshore wind projects while creating hundreds of jobs and millions of dollars of local economic benefit.” 

In the same news release, Dominion said that it would de-risk the CVOW project by taking on a minority investor. And in a filing with the Securities and Exchange Commission in August, Dominion indicated the offshore wind installation vessel it ordered will cost more and take considerably longer to complete than initially projected. 

The Charybdis is notable not only for its sheer size (473 by 184 feet) but because it is being built in Texas: It will be the first U.S.-built vessel of its kind and meet the domestic manufacture requirements of the Jones Act. 

The industry trade group Oceantic Network — which until Monday was known as the Business Network for Offshore Wind — hailed the decision as great news. 

“Dominion’s CVOW project is anchoring a critical corner of the emerging domestic supply chain, and advancing this project means supporting development of America’s first wind turbine installation vessel and substantial port redevelopment work,” Oceantic Vice President John Begala said in a news release. “The Hampton Roads area is abuzz with offshore wind activity and the federal government’s advancement of the CVOW project will continue advancing the area as a hub for the whole industry.” 

BOEM still must approve the construction and operations plan, which would be the final greenlight for CVOW. 

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MISO Selects Ameren to Build 2nd Competitive LRTP Project

MISO has awarded Ameren Transmission Company of Illinois (ATXI) the lead in building a pair of lines and substation in northwest Missouri, the second competitively bid project stemming from the RTO’s $10 billion long-range transmission plan (LRTP).

The Ameren subsidiary plans to partner with the Missouri Joint Municipal Electric Utility Commission on development of the $84 million, 345-kV Fairport-Denny project, extending to the Iowa-Missouri border. ATXI plans to sell 49% of the project to the Missouri state utility agency just before the project is placed in service in 2030.

MISO said ATXI was one of four developers to submit project proposals, with LS Power Midcontinent, NextEra Energy Transmission Midwest and Transource Energy offering nine. MISO does not reveal the companies behind non-winning bids, although it said one developer submitted six proposals based on differing designs. It said proposals ranged from $84 million to $134 million for project implementation. MISO originally estimated the Fairport-Denny project would cost $161 million. The RTO said cost differences between proposals came down to conductor size, substation design and tax liabilities.

Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said ATXI’s proposal incorporates “strong cost containment and a sound design.” MISO said ATXI pledged annual revenue requirement caps and carefully considered pre-construction studies and proposed routes.

“Ameren’s proposal, submitted with its partner MJMEUC, had a substantially lower cost than that of the next closest proposal, which was 36% higher based on the annual costs to customers over 40 years,” Doner said in a press release.

MISO said ATXI will execute a selected developer agreement. Doner said MISO looks forward to “working closely with the developer, regulators and other stakeholders to support a successful and on-time completion of the project.”

In a press release, ATXI President Shawn Schukar said the project bid was the “result of a collaborative effort with many community partners who have the best interests of our state in mind.”

He said ATXI will continue to solicit input from the community to build affordable transmission projects.

MISO is simultaneously managing multiple RFPs related to the first LRTP portfolio.

The grid operator opened an RFP for another LRTP project in March. It seeks bids on the $556 million Denny to Zachary to Thomas Hill 345 kV project, part of which will link up with the Fairport-Denny project. Proposals are due Nov. 14. (See MISO Begins LRTP’s 2nd RFP Process.)

The half-billion-dollar solicitation is MISO’s most expensive request for proposals.

The grid operator also opened two other RFPs in July: the $12 million Deadend to Tremval 345-kV project in Wisconsin and a $23 million, 345-kV line segment from the Iowa-Illinois border to the Ipava substation in Illinois. It will select developers for the trio of projects over 2024.

In May, MISO selected LS Power’s Republic Transmission to build the $77 million Hiple 345-kV line at the Indiana-Michigan border. It’s MISO’s first competitive project surfacing from the LRTP. (See MISO Picks Republic Transmission for 1st LRTP Competitive Project.)

In MISO, competitive transmission developers must be members and must be prequalified to bid on competitive projects. Developers must include a $20,000 application fee and a $100,000 initial deposit to have their bids considered by MISO.

MISO’s decision to go with ATXI for the LRTP competitive builds comes as a right of first refusal (ROFR) bill for downstate Illinois fizzled out, with supporters last week acknowledging they don’t have enough votes in the Democratic-controlled General Assembly to overrule Gov. J.B. Pritzker’s August veto of the ROFR portion of energy legislation approved in the spring. (See Ill. Gov. Vetoes Downstate ROFR for MISO Regional Tx Projects.)

The bill would have given ATXI exclusive rights to build regional MISO transmission lines in its territory and shut down MISO’s competitive bidding process for future projects in downstate Illinois. ATXI backed the legislation.

Recently, ATXI Chairman and President Leonard Singh wrote in a letter to state lawmakers that the company had been “subjected to well-funded misinformation campaigns by out-of-state developers and special interests” who opposed the ROFR.

Singh said a ROFR would keep transmission projects under state — rather than federal — control and remains “the best option to prevent unnecessary delays in construction and hundreds of millions of dollars in potential cost overruns.”

Rep. Larry Walsh (D-Elwood), who sponsored the original measure, said he would reintroduce even broader legislation in spring that seeks to install a permanent ROFR on transmission projects for all utilities in the state.

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EIA: Renewable Curtailments Rising Steadily in CAISO

CAISO’s curtailment of solar and wind power in California is on the rise, and about three-quarters of curtailments so far this year have been from transmission congestion. 

The remainder of curtailments in the first nine months of 2023 were due to oversupply, according to an analysis of CAISO data by the U.S. Energy Information Administration (EIA). 

“Congestion-related curtailments have increased significantly since 2019 because solar generation has been outpacing upgrades in transmission capacity,” EIA said in its report. 

CAISO’s solar and wind curtailments have been increasing since at least 2015, EIA found. Solar made up roughly 95% of the curtailments and wind accounted for the rest. 

In 2022, CAISO’s curtailment of utility-scale solar and wind was 2.4 million MWh, a 63% increase compared with 2021. 

On a month-to-month basis, solar curtailment peaked in April 2023 at 702,883 MWh. That compares to the previous peak of 596,175 MWh in April 2022. 

The increase of solar curtailments in CAISO from 2022 to 2023. As of September, the ISO had curtailed 1.3 million MWh of solar this year, compared with 1.4 million MWh for all of last year. | EIA

CAISO said on its website that it expects to see oversupply conditions more frequently as amounts of renewable resources grow. The ISO is pursuing several strategies to address the issue. 

“Key to curtailment reductions are the interconnection process enhancements, the 2022/23 transmission planning process and increasing amounts of battery storage,” CAISO spokesperson Anne Gonzales told RTO Insider. 

California now has more than 6,600 MW of battery energy storage systems online, up from 770 MW in 2019, the California Energy Commission reported last week. 

CAISO has also pointed to expansion of its Western Energy Imbalance Market (WEIM) as a way to reduce renewable energy oversupply and curtailment. The WEIM allows surplus energy to be shared across the region rather than reducing output. 

According to EIA, trading within the WEIM prevented more than 10% of total possible curtailments in 2022. 

As for CAISO’s upcoming Extended Day-Ahead Market (EDAM), Gonzales said the impact on curtailment would depend on the participation footprint. She noted that energy curtailments occur in real time, while EDAM is a day-ahead market. 

A state-led study last year found “incremental curtailment reductions” in a West-wide EDAM scenario, Gonzales said. 

CAISO has pointed to other strategies that may reduce curtailment, including time-of-use rates and EV charging systems that respond to grid conditions. In addition, policies could be explored to reduce existing generators’ minimum operating levels, making room for more renewable production.  

Storage, Transmission Planning

When asked about EIA curtailment analysis, Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said most solar developers are building solar-plus-storage projects to capture the benefits of meeting net peak demand.  

“In addition, Western regionalization would provide a broader market for excess solar in other states,” Smutny-Jones told RTO Insider. 

Mark Specht, Western states energy manager for the Union of Concerned Scientists, said the fact that most of the solar curtailment in California is due to congestion indicates that solar energy is getting “trapped” in certain locations without sufficient transmission to send it elsewhere. 

A key strategy for solving the problem is coordinated transmission planning across the West, he said. 

Battery storage is another possible way to reduce curtailment, said Specht, who recommended adding batteries to existing solar projects that lack storage. 

Still, Specht said, building all the infrastructure needed to capture every drop of solar energy probably doesn’t make economic sense, and “some amount of curtailment is okay.”  

“Zero curtailment shouldn’t necessarily be the goal,” Specht said. 

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MISO Reports Lower Prices over September Operations

Energy prices continued a year-over-year downward trajectory in September, MISO operations data showed.

The RTO reported real-time energy prices averaged $30/MWh over September, down from $68/MWh during the same period last year. Average natural gas and coal prices both dipped to $2/MMBtu for the month in the footprint, sliding from $8/MMBtu for coal and $7/MMBtu for natural gas in September 2022.

MISO said load for the month peaked at 115 GW on Sept. 5 during a hot weather alert for MISO Midwest. The monthly peak registered higher than last September’s peak of 107 GW. Otherwise, load averaged 77 GW, above last year’s 75-GW average and climbing incrementally from September 2021’s 74-GW average.

Average daily outages for the generation fleet over September were the lowest they’ve been in four years. MISO recorded an average 39 GW in daily outages, down from last September’s 48 GW in outages.

Since September 2020, coal has lost a small amount of ground in the energy mix, while natural gas-fired generation has gained ground. Natural gas has reached 40% of the energy mix, while coal has shrunk to 31%, flip-flopping 2020’s mix, which saw coal leading at 34% and natural gas at 31%.

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FERC OKs Inflation-based Bump to MISO Queue Entry Fee

MISO has received FERC approval to increase its non-refundable interconnection request application fee, required for generation developers to enter the queue.  

As of Tuesday, MISO can raise the circa-2008, $5,000 application fee to catch up with 15 years of inflation and can continue to increase it into the future to keep pace with inflation (ER23-2742). 

MISO interconnection customers pay the nonrefundable application fee alongside each new request for interconnection service. The fee covers MISO’s costs to review interconnection requests, perform studies and facilitate negotiations for generator interconnection agreements.  

MISO will use its original 2008 fee as a starting point and increase it every three years, commensurate with its value in today’s dollars using the inflation calculator from the U.S. Bureau of Labor Statistics. The RTO said it wanted to be able to consistently raise fees and avoid multiple future FERC filings seeking permission.  

FERC said it’s reasonable for MISO to “account for inflation on a consistent schedule and ensure that sufficient study deposit funds are available to cover all necessary expenses. 

“This should contribute to more efficient processing of MISO’s interconnection queue, which will minimize opportunities for undue discrimination and expedite the development of new generation, while protecting reliability and ensuring that rates are just and reasonable,” FERC wrote.   

MISO said for the past 15 years, the application fee has stayed static while its costs to process interconnection requests have increased.  

MISO’s second, refundable study deposit will remain an escalating amount based on megawatt size of the proposed generation project. That deposit ranges from $50,000 for an up-to-6-MW project and up to $640,000 for a 1-GW or greater project. 

MISO’s request for inflation-based fee adjustments is separate from its package of more strict entry and exit rules to relieve pressure on its overcrowded interconnection queue. (See MISO Relaxes Proposal on Stricter Queue Ruleset.)  

MISO will split its suite of stiffer interconnection rules into two filings at FERC. One tackles proposals for tighter land requirements, an automatic penalty schedule for withdrawn projects and increases to the milestone payments MISO collects from interconnection customers as projects move through the queue. 

The other proposes an annual megawatt cap on project submissions according to a feasibility formula. MISO has said there are only so many potential generation projects it can simultaneously consider and still produce accurate interconnection studies.  

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Avangrid to Pay $615K for NERC Violation Penalties

Avangrid has agreed to pay $615,000 to the Northeast Power Coordinating Council for seven separate violations of NERC reliability standards by its utilities in New York and New England, according to a settlement between the regional entity and the company approved by FERC on Friday (NP23-20).

The Avangrid-NPCC settlement was the only notice of penalty filed with the commission by the ERO in September. FERC said in a filing last week that it would not review the agreement, leaving the penalty intact.

NPCC’s allegations involve five of Avangrid’s subsidiaries:

    • New York State Electric and Gas;
    • Rochester Gas and Electric;
    • Central Maine Power;
    • Maine Electric Power (majority owned by CMP); and
    • United Illuminated.

Collectively the companies serve more than 2.2 million electricity customers across New York, Maine and Connecticut. They operate a combined 8,638 miles of transmission lines and 71,000 miles of distribution lines.

The RE accused the utilities of violating several of NERC’s standards, all relating to facility ratings. According to the settlement, the violations began as early as 2007, and in some cases have yet to be resolved. NPCC expects all the remaining issues to be resolved by the end of next year.

Avangrid self-reported all the violations, starting with the initial discovery in February 2020 of an issue on one of NYSEG’s transmission lines between its Hillside and Canton Avenue stations. NYSEG found that the ratings for a 115-kV feeder in its thermal limit database software application differed from those used in its control center and by the application used to perform reliability studies.

Further investigation revealed that although the line had undergone multiple modifications between 2009 and 2019, NYSEG’s rating database had not been updated to reflect their impact on the line’s thermal rating as required by FAC-008-3 (Facility ratings), which was replaced by FAC-008-5 in October 2021. NPCC determined that the noncompliance began in 2012, when NYSEG replaced a breaker at Hillside without updating the rating sheet, and ended in 2019 when the utility correctly updated the sheet.

NYSEG submitted a self-report of another FAC-008-3 violation to NPCC in December of 2020, while fellow Avangrid subsidiary RG&E submitted two self-reports that year concerning infringements of FAC-008-3 and FAC-009-1 (Establish and communicate facility ratings). Following these reports Avangrid conducted an extent of condition review across all its grid transmission assets in New York and Maine.

The review concluded in April 2023, and uncovered errors at 119 of Avangrid’s total facilities. Forty-one affected facilities were owned by NYSEG, 72 by CMP, four by MEPCO and two by RG&E. Sixty of the errors required a reduction in rating.

Avangrid’s review did not reveal ratings errors at any facilities owned by UI, but the utility did report a potential violation of FAC-008-5 to NPCC four days after the review concluded, indicating that it could not locate engineering documentation to support some facility ratings and that there was some confusion about the facility ratings methodology that UI had used. UI’s noncompliance, along with that of CMP and MEPCO, is ongoing and expected to be resolved by next year; the others were reported resolved by 2022.

NPCC determined that the root causes of these violations included ineffective interdepartmental coordination, inadequate internal controls for verifying facility ratings, lack of company-wide rating modification processes and inadequate ratings validation programs.

Avangrid’s mitigation steps include developing a comprehensive transmission facility rating and modeling process, implementing a companywide facility ratings methodology, creating a centralized rating and modeling group and designing a new database to track facility ratings information. The company is also performing an extent-of-condition walkdown, which it expects to finish by the end of 2024 at an estimated cost of $75 million. In addition, it will submit monthly reports through the end of 2024 to disclose any additional facility ratings discrepancies it discovers.

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FERC Approves Extension of Comment Period in PJM CIFP Filings

FERC has approved a nearly one-week extension of the comment period on PJM’s two filings to rework several areas of its capacity market following the conclusion of the Critical Issue Fast Path (CIFP) process in October (ER24-98, ER24-99).

The extension, issued Oct. 27, allows comments to be submitted through the end of Nov. 9, rather than the Nov. 3 deadline PJM sought. PJM Chief Communications Officer Susan Buehler said the extension does not impact the Dec. 12 effective date PJM requested in its filing and therefore would not impact its target to have changes in place for the 2025/26 Base Residual Auction, scheduled to be run in June 2024. (See PJM Files Capacity Market Revamp with FERC.)

The commission did not go as far as the Independent Market Monitor asked when it filed a request for comments to be permitted until Nov. 17, arguing that the intricacy of the filing warrants additional time. The request was supported by American Electric Power, American Municipal Power (AMP), Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition and the Office of the Ohio Consumers’ Counsel.

“The Market Monitor requests an extension of time of 14 days because the filings in these dockets raise important, complex and intricate issues about the design of the PJM capacity markets. More time is required for preparation of an adequate response than the current deadline affords,” the Monitor wrote.

PJM responded that the Monitor and stakeholders should be aware of the changes being proposed in the filing through the months of discussion throughout the CIFP process. Extending the comment period would reduce the amount of time for the commission to evaluate the filing and comments to make a reasoned decision by Dec. 12.

“Specifically, PJM thoroughly discussed the proposed enhancements with all stakeholders, including the Market Monitor, through the Critical Issue Fast Path stakeholder process over a six-month period before the actual filing. Further, the PJM board issued a public letter to all stakeholders detailing the very proposals contained within the underlying dockets nearly one month ago on Sept. 27, 2023,” PJM wrote.

In its comments supporting the Monitor’s request, AMP wrote that the changes being considered could have substantial impacts on the capacity market that should be fully thought out. If full consideration of the proposals leads to the commission not issuing an order prior to the commencement of pre-auction activities, AMP recommended that the commission delay the auction schedule or order it to be run it under the status quo rules.

“If a delay becomes necessary, PJM should seek a revised date for that auction or run it under the existing rules, which have not been found to be unjust, unreasonable or unduly discriminatory. Neither the stakeholders’ nor the commission’s review of PJM’s complex filings should be cramped by PJM’s assertions that allowing two more weeks for comments will materially affect the auction schedule,” AMP said.

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PJM MRC Briefs: Oct. 25, 2023

Markets and Reliability Committee

Proposed Rules for Generation with Co-located Load Rejected

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee rejected a proposal to modify how generators with co-located load not interconnected with the RTO’s grid may participate in its capacity market.

The package, which was sponsored by Exelon in the Market Implementation Committee, received 19.5% support during the Oct. 25 vote. (See “Stakeholders Endorse Proposal on Co-located Load,” PJM MIC Briefs: Aug. 9, 2023.)

The proposal would have required that the generation and load each be separately metered, with the generator being designated as a load-serving entity for the load. The generator would have been billed for the energy consumed by the co-located load as an LSE in settlement.

Exelon Vice President of Federal Regulatory Affairs Sharon Midgley said the proposal would allow the generator to offer its full accredited capability as capacity and require the load to pay for a capacity commitment through LSE charges. She said the proposal would effectively be a net financial derate for capacity market participation.

Constellation Director of Wholesale Market Development Adrien Ford urged the committee to vote against the proposal, referring to her comments during the package’s first read in September arguing, in which she argued that it would violate the Federal Power Act by considering load not receiving energy from PJM’s grid to be FERC jurisdictional.

Midgley responded that the load under the proposal would be retail and end-use.

Independent Market Monitor Joe Bowring said that the IMM opposed the proposal because, despite its designation of the generator as an LSE, it would permit the same capacity to be sold twice.

PJM’s Tim Horger said that several proposed amendments were dropped based on stakeholder feedback in September and a determination that they were not necessary. He offered a friendly amendment, which the commission accepted, to adjust the cost-based offer definition to be in line with changes made throughout the manuals following the shift to cost- and market-based offers. In the event that the larger proposal did not pass, he said that PJM would seek to make the revisions as a standalone manual change.

Stakeholders have been discussing how to account for generators with co-located load, both in configurations where the load is interconnected to the wider PJM grid or only capable of receiving energy from the generator. Several proposals addressing both were voted on by the MIC in August, but none regarding grid-connected load were endorsed, and Exelon’s was the only one for unconnected load to pass.

Stakeholders Mixed on Sunsetting Clean Attribute Procurement STF

Stakeholders are considering terminating the work of the Clean Attribute Procurement Senior Task Force (CAPSTF) following several states opting to form a working group outside the PJM process to explore the creation of a voluntary market for trading clean energy attributes that is not under FERC jurisdiction.

The CAPSTF’s work culminated in three proposals being polled in May, but none received the majority support needed to advance to the MRC. The poll did show overwhelming support for putting the task force on hiatus while the Critical Issue Fast Path (CIFP) process on the capacity market that, initiated in February, ran its course.

The effort is being spearheaded by Ryann Reagan, of the New Jersey Board of Public Utilities, who told RTO Insider that the state working group is primarily focused on a forward clean energy market (FCEM) design, which she said is a process similar to the proposal that received the largest share of support in the poll at 41%.

The concept would allow the trading of products representing clean energy attributes, as well as existing renewable energy credits (RECs). PJM currently administers a registry of RECs through the subsidiary PJM EIS (Environmental Information Services), but it does not facilitate the trading of credits.

The FCEM design would not involve the procurement of capacity outside the Base Residual Auction (BRA); that would be more along the lines of an Integrated Clean Capacity Market, a variant of which received 33% in the poll.

The working group is open to the public, with those interested in participating welcome to reach out to Reagan; PJM and the Brattle Group are participating in addition to the states. The working group has a goal of reaching a general framework for a market design by the end of the year.

Whatever form any market created by the working group takes, Reagan said it’s intended for state participation to be voluntary and also be open for nonstate entities, such as companies with clean energy goals. She said she has heard frustration about the lack of a centralized way to purchase credits, particularly for smaller REC buyers.

The desire to move out of the PJM stakeholder process is partly borne of not wanting to lose momentum at a time that the RTO is beginning work on several significant issues, such as the rules around reserve resources and generation deactivation. She noted that the topic had been discussed at PJM for three years and the CAPSTF has been on hiatus for five months.

Katharine McCormick, of the Illinois Commerce Commission, said the working group is also building on discussions held at the Organization of PJM States Inc. (OPSI) that concluded over the summer. She highlighted a few priorities in the analyses at PJM and OPSI, including that all of Illinois be modeled, so that the impact of any resource deactivations to the southern, MISO-covered portion of the state are considered.

McCormick said Illinois is participating in the working group, but it has not committed to being involved in any final market design that may come out of it. In addition to being able to procure capacity that meets the state’s future clean energy requirements, she said it is also interested in ways of satisfying its capacity needs outside of PJM’s Reliability Pricing Model (RPM).

If the end result of the working group does turn out to be a FERC-jurisdictional market, PJM’s Scott Baker, facilitator of the CAPSTF, said a new forum can be found to hold those discussions.

Vistra’s Erik Heinle said the possibility of the working group yielding a product that is either FERC jurisdictional or has an impact on PJM’s markets that requires stakeholder attention could warrant leaving the task force open for at least a few additional months, especially considering the group’s goal for a framework.

Baker responded that PJM staff considered leaving the task force open but are generally averse to having task forces not actively engaged in work.

Multiple Proposals Considered for Incorporation of Multi-schedule Modeling

The committee discussed two proposals intended to allow modeling of combined cycle and storage resources to be incorporated in the market clearing engine (MCE) without causing computation times to increase to an untenable degree.

Both proposals were endorsed by the MIC at its Oct. 4 meeting and are slated to be considered for MRC endorsement on Nov. 15. (See “Multi-schedule Modeling in Market Clearing Engine,” PJM MIC Briefs: Oct. 4, 2023.)

The main motion, sponsored by PJM, would create a formula to select the offer expected to produce the lowest total dispatch cost and forward only that offer to the MCE. An alternative, jointly sponsored by PJM and GT Power Group, would select resources’ cost-based offers when they fail the three-pivotal-supplier (TPS) market power test and their parameter-limited offers during emergency conditions.

The issue stems from an expectation that the number of schedules that the MCE would have to consider would exponentially increase because of the number of configurations that combined cycle and storage resources can reflect in their offers. The changes are being considered as part of a larger overhaul of the MCE through PJM’s Next Generation Markets (nGEM) project.

GT Power’s Tom Hyzinski said the rationale behind the joint proposal was to find a middle ground between PJM’s proposal to pick a single generator’s offer using a formula, and another proposal that GT Power put forward with the Monitor that would have constructed a single offer using parameters from one offer and incremental costs from another. He said the joint PJM proposal uses the formulaic approach to pick a single offer from among multiple cost-based offers, while the IMM proposal would require the resource owner to select the single cost-based offer.

“The intent here was to move this thing towards the middle,” he said.

Deputy Monitor Catherine Tyler presented an issue with each proposal that she argued would create new ways for generators to avoid market power mitigation without resolving existing issues.

Tyler said PJM’s proposal would result in the RTO only considering offers at their economic minimum (EcoMin) value, even if that offer becomes much more expensive at higher outputs. She gave an example of a resource where the price-based offer is cheapest at its 100-MW EcoMin but which jumps to the $1,000/MWh offer cap when the resource is dispatched above 120 MW. In such a case, she said the cost-based offer should be selected even if it’s more expensive at EcoMin.

The PJM/GT Power proposal and the IMM/GT Power proposal, which was not endorsed by the MIC, would resolve the market power mitigation issue, Tyler said.

Both proposals would also use the PJM total dispatch cost formula to select among multiple cost-based offers, creating a possibility of a dual-fuel resource being dispatched on a fuel that is not the most economical for a portion of the day. Tyler said that could create a dilemma for generators because of the requirement that they base cost-based offers on the most economical fuel or risk being in violation of market manipulation rules.

PJM’s Keyur Patel said that some tradeoffs will have to be accepted to realize the benefits of combined cycle modeling.

“We know that this is not optimal,” he said.

Tyler said that the MRC should endorse the IMM/GT Power proposal, arguing that neither PJM nor GT Power had explained why it would be not the best solution.

Recommended Values for 2023 Reserve Requirement Study

The committee endorsed PJM’s recommended values for the installed reserve margin (IRM) and forecast pool requirement (FPR) components of the annual Reserve Requirement Study (RRS), which would have the effect of increasing the amount of capacity the RTO aims to procure through future BRAs.

The parameters are set to go before the Members Committee in November and to the Board of Managers for final approval in December. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

The IRM, which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year in the 2022 study to 17.6% for the 2027/28 delivery year. The FPR, which includes forced outage rates, also would increase from 9.18% to 11.65% for the corresponding delivery years.

PJM made a handful of changes to how the study is conducted in the wake of December 2022’s Winter Storm Elliott and the changes to the capacity market being considered by FERC through the RTO’s filing resulting from the CIFP. Load models were developed using both the PRISM software PJM has historically used, as well as an hourly loss-of-load model developed from the effective load-carrying capability accreditation studies. PJM also included data from the 2014 polar vortex and Elliott, reversing a historical practice to not include extreme winter storms in the study’s modeling based on the impact of Elliott.

Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-2022 and use that figure, which landed at 1.5%, instead.

The load model, which included data from 2013-2019, contributed to a 2.1-percentage-point increase in the IRM, while the winter peak week caused a 1.1-point increase. The values were slightly lower for the FPR drivers. The 1.5% CBOT contributed to a 0.5-point decline in the IRM value and a 0.58-point-lower FPR.

During a Resource Adequacy Analysis Subcommittee (RAAS) meeting in August, James Wilson, a consultant to state consumer advocates, calculated that the recommended values would constitute an approximate 3,700-MW increase in the summer reserve margin.

New Transmission Outage Coordination Rules

The committee signed off on revisions to Manual 38, which pertains to operations planning, to increase coordination between PJM and transmission owners to capture any potential extended transmission outages not identified by existing processes.

The proposal would add a step after board approval of Regional Transmission Expansion Plan (RTEP) windows for RTO staff and TOs to coordinate the sequencing of their outages and evaluate if any mitigation is needed, such as short-term emergency ratings or upgrades to limiting facilities. (See “Stakeholders Endorse Outage Coordination Manual Revisions,” PJM OC Briefs: Oct. 5, 2023.)

The overall outage coordination package approved by the Operating Committee in June also adds information about outage requests and transmission ratings to PJM’s website to increase transparency. (See PJM OC Briefs: June 8, 2023.)

Members Committee

3 Changes to Stakeholder Process Proposed

The Members Committee discussed first reads on three proposed changes to Manual 34, which sets the structure of the Consensus Based Issue Resolution (CBIR) stakeholder process.

Dayton Light and Power presented a change to the voting structure so that if a main motion fails, any alternative proposals submitted during the period for posting meeting materials would be voted on simultaneously.

Exelon’s Alex Stern presented a proposal that would specify that requests to add an item to a standing committee meeting agenda is considered to be timely when it is made at least seven days in advance. Requests should include a summary of the action that the committee will be asked to consider.

The language would provide committee chairs with discretion to consider agenda items posted within seven days of a meeting in the event of the subject being time sensitive or of unforeseen disruptions, such as PJM website or internet outages.

Chairs may also consider waiving the deadline for non-voting items, such as informational reports, with the suggestion that members instead provide enough time for PJM staff to review for formatting and agenda conformity.

Monitor Bowring asked for clarification on whether the flexibility around informational items would apply to the reports delivered to the MC webinar, which Stern confirmed would be the case.

Stern also presented a second proposed change aiming to clarify that senior standing committees hold final authority over issues considered by task forces and that the lower committees set the order that proposals will be voted on at the MRC and MC.

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Providers See ‘Mixed Signals’ on Demand Response in NYISO

RENSSELAER, N.Y. — Demand response providers in NYISO last week expressed concern that proposed market rule changes will harm the economics of special case resources (SCRs).

“This has not been a good week for demand response,” said Aaron Breidenbaugh, senior director of regulatory affairs at CPower Energy Management, which aggregates demand response and distributed energy resources.

Breidenbaugh’s comment came at the Oct. 26 Installed Capacity/Market Issues Working Groups meeting, where the ISO presented proposed modeling changes that could significantly cut capacity accreditations for SCRs. It followed the Oct. 25 Management Committee meeting, where Potomac Economics, the ISO’s market monitoring unit, proposed that the ISO compensate some capacity suppliers based on their contribution to transmission security, which could also reduce payments to SCRs.

SCRs are demand-side resources whose load can be interrupted at the ISO’s direction or behind-the-meter generators rated 100 kW or higher that can reduce load on the transmission or distribution system.

The ISO says its current modeling of SCRs in the installed reserve margin (IRM), locational capacity requirement (LCR) and capacity accreditation studies is not aligned with SCRs’ actual performance.

It proposes to model SCRs as duration-limited resources with hourly response rates based on historical performance beginning in the 2025/26 capability year. In the interim, the ISO said it will treat SCRs as part of the four-hour energy duration limited capacity accreditation resource class. (See NYISO Previews Capacity Accreditation Modeling Work.)

Breidenbaugh said the ISO’s proposed changes could cut capacity accreditation of SCRs by 20%. He said his company will seek a change in the SCR program “to move from four hours to some other number … in order to avoid gutting the SCR program.”

Breidenbaugh said Potomac’s proposed changes would reduce the payments to SCRs even more than is being contemplated by changes to accreditation rules, saying, “I’d prefer having my revenues reduced by 50% as opposed to 75%, but neither one of them is terribly attractive.”

Breidenbaugh said he’s received “mixed signals,” from the ISO on potential changes to the SCR program, citing NYISO CEO Rich Dewey’s comments at the Multiple Intervenors annual meeting about being willing to make SCR programs more flexible when previous NYISO presentations had suggested no such flexibility. He also cited statements by officials of the New York State Energy Research and Development Authority at the Alliance for Clean Energy New York annual meeting about “how important demand response is and how we aren’t going to meet the requirements in the CLCPA [Climate Leadership and Community Protection Act] without significantly greater demand-side flexibility.” (See Mood Anxious as Renewable Energy Industry Gathers in NY.)

He added that the ISO has made clear “that the future of demand response is the DER participation model — not getting rid of [the SCR program] but [NYISO is] making it so unattractive that the only alternative is to go into the DER participation model.”

The ISO’s DER and aggregation participation model, which will allow heterogenous groups of technologies to be compensated for services that they can provide collectively, was approved by FERC in January 2020 (ER19-2276). (See NYISO DER Participation Model Gets FERC OK.) On Oct. 19, the ISO informed FERC that it would not be implementing the DER participation model until the commission acts on companion tariff changes in docket ER23-2040.

Engaging the Demand Side

Adam Evans, a staffer at the New York Department of Public Service, also expressed concern. Although the ISO’s Short-Term Assessment of Reliability report for the third quarter identified a need to respond to new loads and shrinking margins, he said, “there’s really not much coming out of the Engaging the Demand Side effort,” an initiative to identify problems or gaps in the ISO’s existing demand side programs.

“I am really concerned about the long-term viability of the SCR program,” said Jay Goodman, an attorney with Couch White, which represents large consumer stakeholders. “It seems that with every change layered onto the modeling, the impact generally seems to be in the direction of decreasing [SCRs’] capacity value.

“Our expectation is that SCRs being available is increasingly important, and so it doesn’t make sense to have a … market rule change at a time when we think we need to be able to rely on them more,” Goodman said.

In a presentation in September on the Engaging the Demand Side initiative, the ISO said it was not seeking to eliminate the SCR program but to respond to stakeholders’ requests to modify SCR rules so that resources are compensated for their true operating capabilities.

The ISO said some SCRs can respond to events more frequently than others, and with less than the current 21-hour advance notification requirement. Some also can operate for up to eight hours. “In short, some resources have expressed that they are more flexible than the SCR program allows, but not flexible enough to fully participate in the DER program on dispatch,” the ISO said.

The ISO said it would prefer to modify the DER participation model to tailor it to SCR operating characteristics rather than expanding the SCR program. Unlike the SCR program, which relies on manual actions by NYISO operators, demand-side resources in the DER model are automatically scheduled and dispatched based on the economics of their bids.

Maddy Mohrman, NYISO capacity market design specialist, told the ICAP/MIWG that “the goal of this project really is to come up with a modeling that just better represents the [SCR] program today.”

NYISO will bring the results from its enhanced SCR modeling to the Nov. 1 meeting of the New York State Reliability Council Installed Capacity Subcommittee, which may vote to recommend changes be implemented into future IRM/LCR modeling.

MMU Recommendation

Breidenbaugh said SCRs could also lose revenues under Potomac Economics’ suggestion to the Oct. 25 MC meeting that NYISO implement proposal No. 2022-1 from the MMU’s May State of the Market report.

Potomac’s Pallas LeeVanSchaick reiterated the monitor’s recommendation during a discussion of NYISO’s draft annual Comprehensive Reliability Plan, which the MC recommended be approved by the Board of Directors.

The CRP said that although the probabilistic resource adequacy analysis did not identify any reliability needs, the deterministic transmission security analysis predicts a deficiency for New York city starting in 2031 if the New York Power Authority’s small gas plants, totaling 517 MW, retire without replacement resources.

Overview of factors causing higher resource-adequacy-based New York City margin in 2025 | Potomac Economics

The MMU’s memorandum summarizing its comments on the CRP’s resource adequacy assessment assumes that up to 1,180 MW of “emergency” resources in New York City for 2025, including 219 MW of SCRs. The transmission security assessment does not include emergency actions.

The MMU’s State of the Market report found that SCRs and large resources whose size causes the transmission security planning contingency to increase “provide limited value towards satisfying reliability requirements based on transmission security criteria.”

“Transmission security requirements are increasingly likely to cause higher [locational capacity requirements], especially in New York city. When this occurs, SCRs and large resources will be overcompensated and have inadequate incentives to take actions that would improve system reliability. In the upcoming 2023-24 capability year, we estimate that large resources and SCRs in New York City could be over-compensated by up to $52 million. (See NYISO MMU Calls for Improved Shortage Pricing, More Capacity Zones.)

LeeVanSchaick said the MMU proposes a two-part pricing mechanism that separates resource adequacy and transmission security when transmission security criteria determine the LCR, ensuring SCRs, large contingency resources and intermittent renewables are appropriately compensated based on their contributions to the planning reliability requirements.

LeeVanSchaick pointed to a chart in Potomac’s presentation to the MC that showed a roughly 800-MW difference in the marginal requirement needs for New York city projected by the two assessments. “If you calculate the margins [for New York city] using a transmission security assessment, there’s a deficit in 2025, while a resource adequacy assessment would tell you there’s a surplus,” LeeVanSchaick said.

Breidenbaugh said that under the MMU’s proposal, “you pretty much wouldn’t have any SCRs in New York city.”

Both NYSIO and Potomac acknowledged stakeholders’ concerns but stressed more discussion is forthcoming.

LeeVanSchaick emphasized that Potomac “wanted only to highlight these differences to increase people’s understanding of how the emergence of transmission-security-based capacity requirements are likely to affect investment incentives.”

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Four New Wind Energy Areas Designated in Gulf of Mexico

Four new wind energy areas with a potential capacity of 9.27 GW of power generation have been designated in the Gulf of Mexico.

The Bureau of Ocean Energy Management said Oct. 27 that the sites total 763,000 acres and stand 47 to 82 miles off the Texas and Louisiana shorelines.

A notice of proposed sale will be issued next, with a 60-day public comment period to follow.

The move is part of the Biden administration’s continuing effort to expand offshore wind generation. BOEM conducted the Gulf of Mexico’s first offshore wind area auction in late August with disappointing results: Two of the three wind leases drew no bids, and the third attracted only two bidders, one of whom dropped out after the first round.

The final result: RWE Offshore US Gulf got rights to install up to 1,244 MW on 102,480 acres with a winning bid of $5.6 million. That is less than $55 an acre and compares with top bids of more than $10,000 an acre in a 2022 auction off the New York-New Jersey coast.

BOEM Director Elizabeth Klein alluded to the lackluster results of the August auction as she announced the new wind areas: “Creating an offshore wind industry in the Gulf of Mexico will take time and partnership. BOEM is pursuing another offshore wind lease sale in the Gulf of Mexico due to continued industry interest and feedback from our partners and key stakeholders.”

Multiple factors complicate offshore wind development in the Gulf, starting with the supply chain constraints and soaring costs plaguing the offshore wind industry elsewhere as it attempts to establish itself in the United States.

Also, the Gulf has weaker winds and a softer seabed than the areas being targeted for offshore wind development off the Atlantic and Pacific coasts, plus a greater threat of hurricanes.

Finally, the economics are less than ideal in the Gulf region, where electricity is relatively inexpensive.

On the positive side, there is potential interest in the Gulf region in using offshore wind to power clean hydrogen production. The fossil energy industry has a large offshore presence in the area, making wind turbines more palatable to the public. And Louisiana is encouraging offshore wind development closer to shore, in state waters.

The trade group Business Network for Offshore Wind welcomed BOEM’s announcement and noted that the Gulf region already is playing an important role in U.S. offshore wind development.

In a news release, BNOW Vice President John Begala said:

“With nearly a quarter of U.S. market contracts going to Gulf firms, the area is already the engine for U.S. offshore wind industry; building a robust pipeline of projects will further unlock the true potential of the region’s supply chain capacity. Gulf expertise in offshore construction is unparalleled, and innovative solutions developed there will continue to drive not just the U.S. but the global offshore wind industry forward.”