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November 1, 2024

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Offshore Wind: Analyst Addresses Industry’s Growing Pains

BROOKLYN, N.Y. — Attendees at the Jan. 11 Offshore Wind Supplier Forum were treated to a precise assessment of what they already knew in varying levels of detail: The young U.S. industry had a difficult time in 2023 and has some growing pains ahead in 2024 and beyond. 

BloombergNEF offshore wind analyst Chelsea Jean-Michel said BNEF has reduced its forecast for 2030 installed U.S. offshore wind capacity by 44% due to soaring costs and other struggles. 

Also, BNEF calculates the levelized cost of electricity for new offshore wind projects at 48% higher in 2023 than in 2021, and that is assuming they qualify for the full 40% investment tax credit, rather than 30%. 

And projects totaling more than 12 GW — more than half the U.S. pipeline — have canceled or sought to renegotiate their contracts. 

BNEF’s analysis shows the levelized cost of electricity produced by new offshore wind plants soaring in 2022 and 2023. | BloombergNEF

“I hope I haven’t depressed you all too much,” she said to laughter from the room, after 15 minutes of doing just that. “There is so much to be excited for in the industry and so much to be optimistic for. At BNEF we really do view these struggles as a bump in the road, as a sign of growing pains.” 

Some of the positives: Only 12% of the pipeline is at the highest risk of cancellation; New York reached provisional contract agreement on three large new offshore proposals even amid all the struggles of 2023; up to 14.8 GW of new contracts could be awarded in five states in 2024; and inflation adjustment mechanisms are being offered in the latest offshore solicitations. 

As the offshore wind industry was setting up in the United States, Jean-Michel said, there were some key departures from practices in Europe: States awarded contracts early on in development, rather than later in the process, and compensation was locked in for the life of the contact, rather than with provisions for regular adjustments to reflect rising costs. 

Two of the first offshore projects contracted in the United States — Vineyard Wind 1 and South Fork Wind 1 — were far enough along when costs began to skyrocket in 2022 that they could continue to construction. But several others were not. Two offshore farms have been canceled outright before construction, four others have canceled their contracts, and at least three others are at risk of canceling their contracts. 

The first monopile foundation complete in New Jersey for the Ocean Wind 1 project is shown in mid-2023. Ørsted canceled Ocean Wind 1 and 2 later in 2023 due to the financial and logistic challenges BNEF analyst Chelsea Jean-Michel laid out in her Jan. 11 presentation. | Ørsted

The levelized cost of electricity for all renewables has risen, Jean-Michel said, not just offshore wind. 

Onshore wind turbines cost 30% more than they did before the pandemic, she said. It is harder to track the price of offshore turbines because there are fewer such projects and they are less transparent, she added, but “There is reason to believe that offshore wind prices have followed a very similar trend.” 

Jean-Michel displayed a chart handicapping 20 nations’ offshore wind goals. 

“What’s very telling here is that we don’t think any of these markets are really going to meet their offshore wind targets, except for Taiwan and Poland,” she said. “The U.S. has been hardest hit by some of these macroeconomic pressures.” 

Jean-Michel was asked if she thought there would be a true “return to normal” and an end to the financial problems plaguing the offshore industry. 

She said it is impossible to predict the future, but governments have adjusted policies to account for financial risk; whether it is enough of an accommodation will start to become apparent soon. 

Government support does remain firm at the state and local level. Both states sponsoring Thursday’s forum are bullish on offshore wind as a source of emissions-free energy as well as jobs.  

New York and New Jersey are attempting rapid turnarounds after losing three major offshore projects from their portfolios in two months. They are stepping up collaboration with each other to improve the chances of success, and they are continuing to support offshore development with money and policymaking. 

Greg Lampman of the New York State Energy Research and Development Authority spoke of the scramble underway.  

As onshore and offshore renewable projects cancel unprofitable contracts, NYSERDA is racing to get them (or replacements) back in the pipeline at higher costs through new requests for proposals. “Racing” is not overstating the matter — it is a blistering pace by the standards of the regulatory world. 

“I’ve got to tell you, I didn’t think we could do it,” Lampman said. “This is moving mountains. Our RFP process typically takes about 14 months. We’re doing it in three.” 

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Offshore Wind: Smaller Companies Help Get Steel in the Water off NY

BROOKLYN, N.Y. — Offshore wind development is the sum of many parts, creating many business opportunities beyond the heavy manufacturing and heavy lifting that only a few companies can perform. 

This point was made repeatedly at the New York-New Jersey Offshore Wind Supplier Forum in Brooklyn on Jan. 11. The two states have a combined 20-GW goal and expect those projects to need everything from lighting and security fencing to paving and portable offices to meal delivery and housekeeping. And electrical components, of course. 

“There’s a lot of opportunity for small suppliers, bigger suppliers to come in and deliver goods and services,” said Steffen Bo Clausen of Vestas Wind Systems. 

“It’s an emerging market, but the general approach with Vestas historically, we’ve used the local supply chain in the neighborhood for many things.” 

NetZero Insider spoke to leaders of two very different New York companies that have benefited from offshore wind development. 

The Turnaround

Ljungstrom is one of those success stories that advocates hope offshore wind will nurture in the United States during the transition away from fossil energy. 

The company builds efficiency components for coal-burning power plants at a factory in Wellsville, more than 200 miles from the nearest ocean shoreline.  

And it is located in one of the original U.S. oil patches — legend has it that in 1627, at a spring not far from where the Ljungstrom factory stands today, a French missionary was the first European to see petroleum in North America. 

Ljungstrom’s employee ranks had been shrinking with the coal industry, but that stopped when the company won contracts to build secondary steel components (anode cages, internal platforms, monopile doors) for the South Fork, Revolution and Sunrise offshore wind farms. 

“This has been amazing for our workforce. We’ve hired a hundred people in the last year,” said Nick George, a member of the sales team.  

“Jude’s personal goal here is to never lay off anyone again,” he added, referring to business development manager Jude Auman.  

Ljungstrom had a moment in the spotlight two days earlier, as Gov. Kathy Hochul (D) highlighted its turnaround in the video introduction to her State of the State Address. Auman narrated that segment of the video.  

George and Auman said the transition from coal to marine wind was not difficult. 

“Learning new specs and all that, we’re good at that,” George said. “There’s aches and pains along the way, but for the most part [it’s] an easy transition.” 

Onshore wind has been a harder nut to crack. Ljungstrom could do the work, but it has not been able to get into the supply chain, which is firmly established in the United States. 

The new offshore wind industry has provided an unlikely opportunity for the company and the Allegany County, where the population has been stagnant or shrinking for decades. Census data show a significantly smaller percentage of county residents engaged in the workforce than New Yorkers as a whole and a poverty rate significantly higher in the county than for the state. 

There simply are not very many good jobs. And, not coincidentally, there are not very many skilled workers. 

“I think there’s only 45,000 residents in Allegany County,” George said. “It’s tough to find and keep people.” 

Red Ironworks of Babylon, N.Y., was among the companies that completed the South Fork Wind substation, shown here while work was in progress in 2023. | South Fork Wind

The Growth Curve

Many speakers at the forum emphasized the importance of skilled workers in the equation.  

Red Ironworks CEO Jason Chadee, who spent two months straight at sea helping build the South Fork Wind substation last year, spoke about the importance of having the right people on an installation project. 

“You really have to educate the workforce on what it is to work offshore — you’re not going to have cellphone service, you’re going to be away from your family for some time, those things take a mental toll. These things you have to consider. Some people are on restricted diets. When you go out there, you eat what is supplied.” 

Jason Chadee, CEO of Red Ironworks, is shown at the New York-New Jersey Offshore Wind Supplier Forum in Brooklyn on Jan. 11, 2024. | © RTO Insider LLC

The worst thing for Chadee was not the tight living quarters or lack of cell service, it was the time away from his children when fog and other delaying factors extended his time at sea. 

“I’ll be honest with you, I wasn’t planning to be there for two months, I was planning to be there two weeks,” Chadee said. “I didn’t plan on it, but I did it as a decision for the company.” 

Chadee bought majority ownership of the Long Island company two years ago. It was not specifically a play for the new offshore wind market — he had been following the sector for years as it took shape, but he was focused more on the terrestrial projects that provide the bulk of the company’s work. 

“I used to be a consultant for them. I saw opportunity to grow,” Chadee said. “Since then, we grew about 800%.” 

He thinks experienced onshore ironworkers can transition well to offshore work. As members of the union, they have a minimum of 1,000 hours of classroom training and 6,000 hours of field experience. They can do the tasks involved. The question is whether they want to. 

“I am an ironworker by trade, and all the other ironworkers there, we are accustomed to working very hard and working a lot of overtime for many years,” Chadee said. “The new workforce, that is something they have to consider. I think they need to engage that person, so they know what they are getting into.” 

There will be some attrition, he predicted. 

“Based on the crew they had out there, there’s a couple of them that said they don’t want to do that again. So, there are people I think after their first rotation or two won’t like it. Definitely.” 

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Bill Would Integrate Wash. Cap-and-trade with California-Quebec Program

OLYMPIA, Wash. ​— A bill to link Washington’s cap-and-trade program with the California-Quebec combined system drew no immediate opposition when it was introduced Jan. 12 but did collect several requests for technical changes.

The Washington Senate’s Energy, Environment and Technology Committee that day held a hearing for Senate Bill 6058, which would make the state’s cap-and-invest program mesh seamlessly with the longer-running programs dominated by California.

For Washington, the proposed linkage would allow its emitting industries to participate in a larger market for carbon allowances, which theoretically should bring down allowance prices. That should have the knock-on effect of reducing the state’s high gasoline prices, which opponents of cap-and-invest blame on Washington’s unexpectedly high Washington carbon allowance (WCA) prices being passed on by oil refiners. (See Group Says Inslee, Dems Knew About Cap-and-invest Impact.)

“This will help bring down costs for customers,” Matt Miller, a lobbyist for Puget Sound Energy, said at the hearing.

Washington’s one-year-old cap-and-invest program has added 21 cents to 50 cents per gallon at the pump, depending on how the calculations are done. Quarterly auction settlement prices for WCAs ranged from $48.50 to $63.03 in 2023, much higher than state experts predicted in 2021. By comparison, California’s settlement prices started at $10 in 2012 and reached slightly above $36 last year.

Energy, Environment and Technology Committee Chair Joe Nguyen (D), the sponsor of SB 6058, said joining the larger California-Quebec market would reduce and stabilize Washington auction prices. Nguyen said the larger market would encourage other states eventually to join it to further reduce prices. New York currently is designing its own cap-and-trade program to manage carbon emissions.

“We have folks looking at us and trying something similar,” Nguyen said.

In his testimony, Tom Wolf, a lobbyist for BP America, echoed Nguyen’s views.

The earliest the linkage could occur is 2025. However, a public referendum on repealing the entire cap-and-invest program goes to Washington voters in November. If passed, the referendum would nullify the proposed legislation. (See Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State.)

Most of the proposed changes to the bill are highly technical details. The biggest would allow a single bidder in a quarterly auction to obtain up to 25% of the allowances for sale, up from the current 10%. However, a single bidder still would be limited to obtaining no more than 10% of the allowances offered in a calendar year.

Environmental organizations largely supported the bill during the Jan. 12 testimony, but Sept Gernez, acting director of the Washington chapter of the Sierra Club, worried that trimming allowance prices would reduce cap-and-invest revenue going to the state’s climate change mitigation efforts.

Oil and business interests supported the idea of linking with California and Quebec but requested several technical changes.

Even the Washington Policy Center, which wants to eliminate the cap-and-invest program because of gas price hikes, supported the concept of linkage to reduce auction prices. However, Todd Myers, the WPC’s environmental issues director, wondered if a wider cap-and-trade market would bring outside political and economic pressures into the Washington system.

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PJM PC/TEAC Briefs: Jan. 9, 2024

Planning Committee

PJM Presents Long-term Planning Proposal

PJM presented a quick fix proposal to introduce a new long-term transmission planning approach that would include a longer 15-year horizon and consider state legislation that could affect generator participation in RTO markets. 

In giving a first read of the proposal during the Dec. 9 Planning Committee meeting, PJM’s Michael Herman said it would establish five long-term scenarios:  

    • Two base cases 8 and 15 years in advance; 
    • Two 8- and 15-year scenarios assuming a medium amount of new entry prompted by state legislation; and 
    • One high new-entry scenario looking 15 years in advance and including policy goals not backed by legislation. The proposal includes changes to Manual 14B and 14F. 

The base scenarios would focus on the grid’s future reliability needs based on load forecasting, expected generation deactivations, and new resources in the interconnection queue and expected to be online within the scenario’s horizon.  

Thermal and voltage analysis would be performed on the 8-year base scenario, replacing the existing 10-year model for voltage analysis, and would be used to inform the 5-year Regional Transmission Expansion Plan (RTEP) near-term process. Thermal and some voltage analysis would be performed on the 15-year scenario. 

PJM’s Jonathan Kern said the proposal is meant to bolster PJM’s process for addressing localized reliability issues on the transmission grid rather than targeting global resource adequacy and create new scenarios to meet various goals. The RTO also would make changes to the near-term planning process to ensure the long-term approach is harmonized. 

“We want to have an efficient planning process, so we don’t want to have a big disconnect,” Kern said. 

The current two-year planning cycle would be extended to three years to reflect the increased number of scenarios and sensitivities. 

Exelon’s Alex Stern said this was the first time stakeholders had the opportunity to review proposed manual changes. He identified three challenges that have not been addressed:  

    • How projects that address both grid reliability needs and state policy goals would fit into the planning process;   
    • How PJM proposes to delineate between local reliability and regional reliability; and 
    • Where and how economic reviews will be applied. 

PJM plans to seek PC endorsement of the quick fix proposal during its Feb. 6 meeting and, if endorsed, bring it to the Markets and Reliability Committee later that month for a first read. The quick fix process allows an issue charge and problem statement to be voted on concurrently with a proposed solution. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, expressed concerned about how often PJM has been using the quick fix process to propose manual changes in recent months and questioned the necessity of using it in this case. 

Stern said he was focused on providing substantive feedback, but conceded the manual changes likely will require a level of discussion beyond the quick fix process. He worried that questions surrounding PJM’s legal authority could put a cloud over any planning that flows from the changes, such that the long-term regional transmission planning analysis will be unable to produce feasible transmission projects. 

PJM reviewed proposed updates to the TO/TOP Matrix, which indexes standards that transmission owners and PJM must comply with and delineates responsibilities to ensure compliance. 

The changes include revisions to reflect emergency operations standards NERC approved in October under EOP-011-4, which includes operating plan requirements for emergencies related to “critical natural gas infrastructure loads that fuel a significant portion of … generation.” (See NERC Board Approves Cold Weather Standards.) 

If approved by the Transmission Owners Agreement-Administrative Committee (TOA-AC), the revised matrix would become effective April 1. 

Transmission Expansion Advisory Committee

PJM Presents 2024 RTEP Timeline

PJM is building base cases for its 2024 Regional Transmission Expansion Plan (RTEP) and accepting proposed changes to its basic assumptions, such as modeling, as long as they are expected to have a significant impact on baseline studies. It also will accept corrections to its analytical files. Feedback can be provided through March, when PJM plans to begin the baseline studies.  

The RTO seeks to open an RTEP competitive window in June or July, including a potential retool of the baseline analysis if needed. Review and approval of project proposals is planned to occur between October and February 2025. 

Supplemental Projects

Exelon presented a project to replace a 230/69-kV transformer at its Atlantic City Electric Mickleton Substation for $5.9 million. The existing transformer was installed in 1987 and is experiencing insulation wear and cooling issues. The project, which has a projected in-service date of May 31, 2025, is in the engineering phase. 

Dominion presented a $12.3 million project to construct a new 230-kV Lost City substation to serve a data center planned in Henrico County, Va. The proposed facility would cut into the existing White Oak-Techpark Place 230-kV line and has an estimated in-service date of July 1, 2025. 

FirstEnergy presented several projects to replace transformers experiencing consistent maintenance issues or at the end of their lifespan. A 230/34.5-kV transformer at the Kittatinny Substation would be replaced with a 90-MVA unit for $7 million; two 230/34.5-kV transformers at the East Flemington Substation would be replaced with 125-MVA units for $14.36 million; and a 230/115-kV transformer at the Raritan River Substation would be replaced with a 224-MVA unit for $5.4 million. The projects also include related upgrades to relaying and breakers. 

The utility also proposed a project to replace relays and conductors at its Whippany Substation for $2.33 million to replace outdated equipment lacking spare parts. 

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PJM MIC Briefs: Jan. 10, 2024

Simulation Analysis of PJM CIFP-RA Filing

PJM’s Market Implementation Committee discussed the RTO’s analysis of how proposed Critical Issue Fast Path (CIFP) filings before FERC might have impacted the 2024/25 Base Residual Auction results.

The item was originally listed as informational only, but stakeholders voted to add it as a full agenda item for further discussion.

A total of 136,232.7 MW of unforced capacity (UCAP) was procured in the simulated auction, a 11,246-MW decrease from the actual results. However, the cost to procure that capacity increased from $2.2 billion to $2.4 billion. That trend was on display in the “rest-of-RTO” region, where the clearing price increased from $28.92/MW-day to $47.70/MW-day while the amount procured fell. (See PJM Capacity Prices Jump in 5 Regions.)

“There are a lot of moving pieces here. This is in part because the changes in accreditation types hit some regions differently,” Walter Graf, PJM’s senior director of economics, told the MIC during its Jan. 10 meeting.

PJM’s Skyler Marzewski said the CIFP changes are intended to increase the reliability value of a megawatt of accredited capacity, so even with fewer megawatts clearing the auction, reliability could improve as more efficient units received capacity commitments. In regions where capacity prices declined, Marzewski said, the more efficient resources being picked up in the simulated auction could allow for the same degree of reliability at a lower price.

Calpine’s David “Scarp” Scarpignato said that may account for some of the difference, but the sharp drops in some regions indicated there must be other factors. He pointed to the Eastern Mid-Atlantic Area Council (MAAC) region, where the clearing price fell from $54.95/MW-day in the actual auction to $47.70 in the simulation, while the simulation declined 9% from the 39,303 MW actually committed.

“It’s just so overwhelming, the difference … it looks to me like the amount of reliability you’re purchasing is going down,” he said.

Several stakeholders questioned how the resource mix differed in the simulated auction, but PJM said the information was not yet available.

Marzewski said the analysis is not meant to be taken as a trend or indicative of future auction results, which likely are to be influenced by changing market conditions.

Real-time Temporary Exceptions Manual Revisions Proposed

PJM’s Lauren Strella Wahba presented proposed revisions to Manual 11, which pertains to energy and ancillary services market operations, to reflect FERC’s Nov. 30 approval of a process for market sellers to submit temporary exceptions from their unit-specific parameters.

The revisions would replace the real-time values process PJM used for market sellers to submit changes to their ability to operate according to their parameters during the operating day. (See “Temporary Exceptions Supplant Real Time Values,” PJM MIC Briefs: Dec. 6, 2023.)

Wahba said only one temporary exception should be submitted for an issue preventing a resource from operating according to its parameters. If the issue is expected to last more than 30 days, a period exception instead should be submitted with accompanying documentation showing the disruption is persistent. The market seller should notify both PJM and the IMM of any changes in the physical condition of a resource operating with a temporary exception or the ability to return to normal operations.

Because FERC’s order had an effective date of Nov. 30, Wahba said, the manual changes are conforming language codifying a practice put in place last year.

Quick Fix Proposal on Interface Pricing Points

PJM presented a quick fix proposal to revise Manual 11 to reflect existing practices for interface pricing points, a mechanism that groups buses together when calculating LMPs for energy imports to, or exports from, external areas.

The quick fix process allows a proposed solution to be brought and voted on concurrent with a problem statement and issue charge.

The revisions also would include a recommendation from the Independent Market Monitor to monitor all interfaces as needed — language that exists in the Operating Agreement but is not mirrored in the manuals.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned the need for using the quick fix process in this instance and said PJM increasingly has been relying on the expedited process, making it difficult to ensure stakeholders fully understand changes being made.

“Here we are again, with yet again another issue that we’re using the quick fix process for without a meaningful discussion of how these changes are going to be made so people can understand them,” he said. “I want to express more and more concern about PJM’s use, and I dare say abuse, of the quick fix process.”

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PJM Requests 2nd Talen Generator Delay Retirement

PJM has asked Talen Energy to enter into a reliability-must-run (RMR) contract to continue operating its oil-fired H.A. Wagner generator, located outside Baltimore, three years beyond its requested retirement date in 2025. 

In its Oct. 16 deactivation request, Talen asked to take the generator offline on June 1, 2025, citing air quality restrictions that limit its run time and the economics of PJM’s capacity market as prompting the retirement. Wagner is configured with three oil units and one gas-fired combustion turbine; PJM’s request would retain the oil-fired Units 3 and 4, which output 305 and 397 MW, respectively. 

“The Wagner facilities’ [Clean Air Act] Title V air permit limits operation to capacity factors under 15% when operating on oil. … The combination of low margin energy market economics, low capacity prices and significant Capacity Performance penalty risk due to run hour limitations results in the economics being outweighed by the risk associated with continued operation,” Talen said. 

During the Oct. 9 Transmission Expansion Advisory Committee meeting, PJM’s Perry Ng said the RTO’s reliability analysis found that taking the 844-MW generator offline in 2025 would cause voltage and thermal violations throughout the Baltimore Gas and Electric region. The projected issues were identified when the Wagner retirement was combined with the deactivation of Talen’s 1,283-MW Brandon Shores generator, which the company also requested to go offline in 2025 and is adjacent to Wagner. 

By delaying the retirement by three years, Ng said planned transmission upgrades could be completed and resolve the violations without any new Regional Transmission Expansion Plan projects. In particular, he said a component of the $5 billion package of transmission projects that the Board of Managers approved in December would resolve the violations. That component, the construction of the 65-mile, 500-kV North Delta-High Ridge line and upgrades to both substations, is projected to be in service between 2026 and 2028. (See PJM Board Approves $5 Billion Transmission Expansion.) 

PJM has also asked Talen to continue operating Brandon Shores on an RMR contract through 2028, though Senior Manager of Transmission Planning Sami Abdulsalam said the discussions on the contract are still in progress. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades,” PJM PC/TEAC Briefs: June 6, 2023.) 

Since the start of December, Ng said an additional four generators have requested full or partial deactivation: 

    • Constellation Energy has requested deactivation of Eddystone Units 3 and 4, totaling 760 MW, on May 31, 2025. The generator is a dual-fuel resource located outside Philadelphia. 
    • Archaea Energy requested deactivation of its 11-MW, methane-powered Virginia Beach LF generator on April 1. 
    • GenOn Energy Management requested (here and here) deactivation of four CTs, amounting to 216 MW, at its Morgantown Generating Station near Newburg, Md., on June 1. 
    • Heritage Power requested deactivation of its four dual-fuel CTs at the Sayreville Energy Center, amounting to 217 MW. The company cites a New Jersey Department of Environmental Protection rule limiting emissions effective June 1, which is the date the company requests that the generator goes offline. The notice suggests the possibility the company may make modifications to the site to allow it to resume operations in compliance with the regulations or that it may permanently retire.
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PJM OC Briefs: Jan. 11, 2024

RTOs Submit Comments on EPA Rules

PJM reviewed comments it submitted jointly with other RTOs on EPA’s proposed regulations on greenhouse gas emissions from power plants to the Operating Committee during its Jan. 11 meeting.

The comments also were signed by MISO, ERCOT and SPP and largely focused on allowing them to maintain their ability to ensure resource adequacy and call on specific units during emergency scenarios.

PJM’s Gary Helm said the grid operators warned that the timeline for requiring carbon capture or hydrogen fuel blending for coal and gas resources could quicken the pace of generator deactivations. They recommended rethinking the requirements for new combustion turbine units, as EPA’s proposed rule would require that new CTs include either carbon capture or hydrogen blending when they are brought online. They argued that the infrastructure to support either of those capabilities does not yet exist. Rather than looking at what technologies exist, they urged EPA to also consider what infrastructure is available to make that technology accessible to generators. (See FERC Dives into Reliability Implications of EPA’s Power Plant Rule.)

The proposal “is pretty far reaching, and because of the stringency of the requirements, we’re looking at seeing retirements … as well as limitation on the operation of gas-fired generation,” Helm said.

The grid operators also provided recommendations for creating a “safety valve” to ensure that resource adequacy is not compromised by the rule, including identifying units that may be needed to maintain reliability; a “regional bank” of reliability credits that could be used to operate during emergencies; guidance for states to create resource adequacy and reliability plans; and direction on the agency’s thinking on the remaining useful life of assets.

System Operating Metrics

PJM saw two days outside its 3% target load forecast error during December, according to the system operations report delivered by Stephanie Schwarz, manager of markets coordination.

The RTO underforecast load by just over 4% on Dec. 3, while the forecast for Dec. 24 was about 3.5% above actual conditions. December also saw a shortage case approved Dec. 1, which Schwarz attributed to load, interchange and intermittent generation being affected by shifting weather patterns.

Two spin responses were implemented Dec. 14 and 19 lasting 12 minutes and 15 seconds and 6.5 minutes, respectively. The Dec. 14 event had an assignment of 2,712 MW and a response rate of 1,436 MW, leading to 1,276 MW of penalties being assessed. The Dec. 19 event had a full response from the 2,687 MW it deployed.

Other Committee Business

PJM Director of Enterprise Information Security Jim Gluck urged market participants to remain vigilant for possible social engineering and phishing intrusion attempts aimed at gaining access to computer systems and locking users out for a ransom. He said there have been a growing number of attacks that include individualized research into companies in an attempt to make messages more authentic, including impersonating employees.

The RTO also presented a quick-fix proposal to revise Manual 3A to change language pertaining to the Bulk Electric System to conform to NERC-approved definitions.

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Oregon RA Rules Could Favor WRAP Participation

Oregon regulators are moving closer to adopting resource adequacy rules that would incentivize load-serving entities to join the Western Power Pool’s WRAP. 

But during an Oregon Public Utility Commission rulemaking hearing Jan. 11, stakeholders continued to debate transmission forward-showing requirements and the need to allow a capacity backstop charge. 

OPUC filed the proposed resource adequacy rules in September, following an informal process that began in December 2020. 

OPUC staff contend that “resource adequacy concerns are best addressed through regional coordination,” Curtis Dlouhy, senior economist and policy analyst with the agency, said during the hearing. In particular, Western Power Pool (WPP) offers the Western Resource Adequacy Program (WRAP), the West’s first regional reliability planning and compliance program.  

FERC approved the WRAP tariff in February. (See FERC Approves Western Resource Adequacy Program.) 

OPUC’s proposed rule would incentivize WRAP participation by including more stringent resource adequacy planning for those not involved with WRAP, Dlouhy said. 

OPUC-regulated entities that are not WRAP participants would face a two-year forward-showing requirement for resource adequacy. In contrast, WRAP participants must submit resource adequacy forward showings seven months ahead of a season. WPP then evaluates the submission to ensure the participant is meeting its share of the WRAP planning reserve margin. 

“Entities not attached to a regional program have a greater resource adequacy risk and thus should be subject to uniformly stricter requirements,” Dlouhy said. 

“Staff also believes that requirements consistent with WRAP, albeit stricter, provide a clear incentive to join WRAP and thus benefit from a diverse set of energy producers that are involved in WRAP,” he added. 

Capacity Backstop Discussed

The proposed resource adequacy rules would apply to two types of load-serving entities: investor-owned utilities and electric service suppliers (ESSs). Oregon’s Direct Access program allows nonresidential consumers to buy electricity from an OPUC-certified ESS. 

In written comments, the Northwest & Intermountain Power Producers Coalition (NIPPC) said the commission should give ESSs the option to meet their resource adequacy obligations through a capacity backstop charge. Under that option, direct access customers would pay an RA charge to the utility. 

In addition, NIPPC wrote, WRAP’s firm transmission requirement is “very problematic” and shouldn’t be mandatory. NIPPC represents competitive electricity market participants, including ESSs. 

During the hearing, Greg Adams, representing Calpine Energy Solutions, said that WRAP “requires a real shift in regional transmission practices toward advanced procurement of firm transmission.” 

That’s an issue, Adams said, because of Bonneville Power Administration’s current practice of releasing substantial transmission for purchase less than seven months ahead of delivery. 

“There is significant concern with the ability of all load-responsible entities to meet the WRAP’s forward-showing transmission requirement, given the general … inability to obtain incremental, firm, point-to-point Bonneville Power Administration transmission in the forward-showing timeline — seven months in advance of the time of delivery,” Adams said. 

‘Equal Playing Field’

But Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), noted that under FERC’s open access policy, “all entities are on an equal playing field when it comes to acquiring transmission rights.” She said it was unclear what was preventing direct-access LSEs from procuring long-term, firm transmission. 

“We do recognize that procuring long-term, firm transmission on an annual basis … can be more expensive,” Sporborg said. “But we believe that this is a necessary investment to provide really reliable load service.” 

As for the capacity backstop charge, PGE’s Sam Newman said the utility had concerns. 

“We are very uncomfortable with a scenario where the utilities are required to offer a backstop charge, but as a backstop charge there would be considerable flexibility for direct access load to choose or not choose to lean on that charge,” Newman said. “That puts the utilities in a difficult position.” 

Dlouhy with OPUC said there aren’t currently plans to include a capacity backstop charge in the resource adequacy rules, although that could be reevaluated later. He said the rules would be able to function without it. 

“Staff was not confident that significant excess IOU capacity or transmission existed at the moment,” Dlouhy said. 

The proposed rules also include information filing requirements. Oregon’s IOUs would be required to include a resource adequacy assessment covering at least four years in their integrated resource plans. Electric service suppliers would add the RA information to their emissions planning reports. 

Written comments on OPUC’s proposed rules are due Jan. 25 at 3 p.m. 

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NY State Reliability Council Executive Committee Briefs: Jan. 12, 2024

Gas Constraints

NYISO briefed the New York State Reliability Council Executive Committee (NYSRC EC) on an upcoming white paper to propose updates to the ISO’s resource adequacy modeling, including a recommendation to use a tiered load-based approach to estimate gas availability during the coldest winter days. 

Slated to be released by the end of the first quarter, the white paper comes in response to findings by NYISO’s Market Monitoring Unit, Potomac Economics, which found that eastern New York faces significant gas availability issues during peak cold conditions due to regional pipeline constraints. 

Con Edison’s Howard Kosel, the new chair of the NYSRC’s Installed Capacity Subcommittee (ICS), told the EC that NYISO is likely to recommend incorporating a tiered methodology based on load levels in its winter RA modeling to determine gas availability. This approach would assume no gas availability at loads exceeding 26,000 MW.  

The recommendation is based on Potomac’s observation that constraints in eastern New York during the coldest peak winter days were not being accurately modeled. Consequently, the ISO’s RA modeling during these periods was undervaluing certain generators and failing to anticipate the necessary level of gas procurement before peak winter days. 

The ICS will track the ISO’s progress and plans to share the white paper’s findings with the EC once published.  

PRR-151

The Reliability Rules Subcommittee (RRS) also briefed the EC about comments received on Proposed Reliability Rule 151 (PRR-151), which includes suggestions for adjustments to attestation requirements and the introduction of exemptions for evolving technologies. 

The NYSRC developed PRR-151 to address gaps in NYISO’s current interconnection criteria for inverter-based resources (IBRs) and establish standardized rules for IBRs larger than 20 MW. The committee endorsed industry comments on PRR-151 late last year. (See NY Reliability Council OKs Interconnection Standards for Large IBRs.) 

AES Clean Energy, Ørsted, GE and Alliance for Clean Energy New York submitted comments, aiming to ensure PRR-151 remains flexible and does not hinder the integration of IBRs in the future. 

Roger Clayton, chair of the RSS, said the plan is to modify PRR-151 based on the comments received, with the expectation that the revised rule will be presented to and approved by the EC at its next meeting in February. 

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Appeals Court Rejects Review of AEP Transmission Rates

The D.C. Circuit Court of Appeals last week rejected four Texas cooperatives’ request to review a 2019 FERC decision over American Electric Power’s (AEP) transmission rates, saying the commission properly interpreted the terms of AEP’s tariff (22-1166).

The Jan. 11 order is part of a proceeding that stems from FERC’s approval of a settlement allowing AEP to transition its rates from a historical formula rate to a forward-looking formula rate and remove directly assignable transmission costs related to generation. East Texas Electric Cooperative, Northeast Texas Electric Cooperative and Golden Spread Electric Cooperative agreed to the settlement. Arkansas Electric Cooperative Co. intervened but did not join the settlement or oppose it.

AEP’s 2020 annual update filed with FERC included the true-up calculations to be charged for transmission services provided in 2019. The cooperatives challenged the update and raised several issues that could not be resolved through the preliminary challenge process. The commission rejected several of the asserted error claims and a request for retroactive relief, leading to the cooperatives’ petition for review. (See FERC Partially Grants Challenges to AEP Transmission Rates.)

The cooperatives appealed four rulings in the order: one concerning FERC’s interpretation of the protocols to preclude relief for errors that allegedly occurred in prior rate years and three arguments that took issue with the inclusion of certain cost inputs in the 2019 charged rate.

The appeals court agreed with FERC that refunds for errors made in previous rate years are barred under its governing protocols and that the protocols are controlling. It rejected the cooperatives’ other three arguments, saying FERC’s order is reasonable and “adequately explained.”

“We are ‘particularly deferential to the commission’s expertise’ in making highly technical rate classifications,” Circuit Judge Florence Pan wrote.

Pan was one of three judges who heard former President Donald Trump’s immunity claims from criminal charges Jan. 9.

FERC Approves SPP Revisions

FERC on Jan. 11 accepted SPP’s tariff revisions that clarify the RTO’s multiday reliability assessment (MDRA) process, how the day-ahead market consumes commitments made through the process, and how those commitments are compensated through settlements (ER23-2927).

The commission said SPP’s proposal gives it flexibility in addressing system needs through the MDRA process ahead of extreme weather events and helps incentivize resources to perform when the grid faces reliability risks. FERC said the revisions help resources committed during the MDRA process manage fuel price volatility during extreme weather events.

The MDRA process is SPP’s only way to commit resources in advance of its day-ahead market. It studies systems to help determine whether to commit resources and to provide notice to resources that they be online and should procure fuel. SPP said the revisions do not fundamentally change the process’ core concepts.

The RTO said its proposal was informed by its experiences during the 2021 and 2022 winter storms, when it was forced to import capacity from neighbors to meet demand.