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November 1, 2024

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Bill Seeks to Promote Clean Aviation Fuel in Washington

A legislative effort to make Washington more attractive to the alternative jet fuel industry has reached the state Senate’s Ways and Means Committee.

The committee scheduled a Feb. 20 hearing on Senate Bill 5447 , which would set a business and occupation (B&O) tax rate of 0.275% for any plant that would produce at least 20 million gallons a year of low-carbon jet fuel. A B&O tax is a tax on a business’ gross receipts, and most B&O rates in Washington range from 0.47% to 0.9%.

Senate Majority Leader Andy Billig (D) and Rep. Vandana Slatter (D) each introduced versions of the bill in their respective chambers. It is a common behind-the-scenes legislative practice to pick one of two similar bills to send to both chambers, while letting the other stall in committee. Billig’s bill was selected to advance further in the legislature.

The Port of Seattle has expressed interest in using jet biofuels at SeaTac International Airport since 2017. Low-carbon biofuels would be mixed with existing petroleum-based jet fuels to reduce their carbon intensity.

The only existing alternative jet fuels plant on the West Coast is near Los Angeles, and the two proposed bills seek to develop a second plant in Washington. A few years ago, the predicted cost of building such a plant was at least $1 billion.

Support for SB 5447 was overwhelming at a Feb. 1 hearing before the Senate Environment, Energy and Technology Committee. Supporters included Alaska Air Group (NYSE:ALK), Delta Air Lines (NYSE:DAL), sustainable aviation fuel supplier SkyNRG, BP America (NYSE:BP), the Port of Seattle, Amazon (NASDAQ:AMZN), Washington State University and the Association of Washington Business.

Their representatives said the aviation fuels sector is difficult to decarbonize, but that the effort is needed to meet the state’s goal to eliminate most of its greenhouse gas emissions by 2050. The low tax rate will attract alternative fuel plants, they said.

At a Feb. 7 hearing before the House Environment and Energy Committee, Darrin Morgan, a representative of Netherlands-based SkyNRG, said: “We’d like a facility to be here in Washington state.”

“We have a chance to capture the market,” Slatter said. “With this bill, Washington would be a leader in this new industry.”

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California Energy Commission Grants $31M to Manufacture Futuristic ZEVs

The California Energy Commission on Wednesday continued its recent practice of making large grants to in-state manufacturers of zero-emission vehicles, including futuristic three-wheeled cars with built-in solar panels and hydrogen-powered big rigs.

The CEC awarded Aptera Motors Corp. $22 million to “produce an affordable solar ZEV that uses the sun to fuel up to a 40-mile daily commute without the need for grid-connected charging,” the agency said in a grant document.

The car’s range on a plug-in charge is up to 1,000 miles in a version with the most battery capacity, Aptera says on its website. Other versions can reach 250, 400 and 600 miles on a charge, the company says.

“That looks like a Jetsons kind of [vehicle]. Is that something that is capable of going freeway speeds?” CEC Chair David Hochschild asked Pablo Ucar, Aptera’s vice president of production and procurement.

The car’s top speed is 110 mph, “so it drives like a real vehicle,” Ucar said. “The reason it is a three-wheeler is because we want it to be the most efficient vehicle in the world. Three wheels are more efficient than four wheels. It is a two-passenger vehicle. It performs and behaves like a regular car on the highway.”

The CEC grant, matched by $26.4 million from Aptera, will pay for installing vehicle production equipment at two manufacturing facilities in Carlsbad and Vista, California, cities in San Diego County.

The vehicle is on preorder and expected to be available to buyers later this year. Aptera plans to produce 20,000 vehicles annually by 2025 and to create 444 manufacturing jobs, the CEC said.

Commissioner Patty Monahan, the lead commissioner for transportation programs, acknowledged Aptera’s car is unlike anything on the road in the U.S. and involves uncertainty. But one of the CEC’s goals is to encourage new concepts in zero-emission vehicles from companies such as Aptera, she said.

“We’re taking calculated risks in terms of really wanting to support innovation in the ZEV ecosystem and recognizing that electrification offers this opportunity to be really innovative,” Monahan said.

The CEC approved a $9 million grant to Symbio North America, with a company match of nearly $11 million, to expand its facility in Poway, also in San Diego County, and to establish a new facility in Temecula, in Riverside County, for hydrogen fuel cell vehicle power systems and vehicle assembly. The expansion will create 63 jobs and establish a hydrogen fuel cell workforce training program in partnership with nearby universities and colleges, the company said.

“These California facilities will assemble regional long-haul heavy-duty fuel cell class 8 trucks and have an annual combined maximum production capacity of 250 trucks and 250 to 300 fuel cell power systems to expedite fuel cell truck deployment in California,” the grant request said.

Hochschild asked Symbio North America General Manager Rob Del Core how the company’s big rigs would compare with battery-powered electric trucks being produced by Tesla and others.

“We’re looking at applications where a hydrogen fuel cell could really dominate in terms of the benefits for things like fast-fueling, long range and of course payload capacity,” Del Core said.

That will include trucks that can travel 400 miles from Southern to Northern California without refueling on a route with 70 mph highway speeds and a winding 4,000-foot mountain pass.

The CEC’s grants are part of a major push to encourage ZEV manufacturing and job creation in California using funds allocated by state budgets in 2021 and 2022.

As of January, CEC staff had recommended 13 projects for funding totaling $199.4 million.

Last month the CEC awarded more than $46 million in grants to four manufacturers of electric tractors, forklifts, car batteries, and charging stations with the intent to bolster in-state production of zero-emission vehicles and equipment.

Ranging from about $8 million to more than $14 million, the grants were among the largest manufacturing subsidies ever granted by the CEC. (See CEC Awards $46 Million for ZEV Manufacturing.)

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PJM MRC/MC Preview: Feb. 23, 2023

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

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

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

As part of its consent agenda, the MRC will be asked to endorse:

B. proposed revisions to Manual 27: Open Access Transmission Tariff Accounting to conform to the settlement agreement approved by FERC in PJM’s filing to change its administrative cost recovery charges (ER22-26).

C. proposed revisions to Manual 40: Training and Certification Requirements resulting from a periodic review.

Endorsements (9:10-9:20)

3. Manual 6 FTR Bid Limits (9:10-9:20)

PJM’s Emmy Messina will present a proposal to increase the number of bids a corporate entity may submit into FTR auctions, alongside corresponding revisions in Manual 6: Financial Transmission Rights. The committee will be asked  to endorse the proposed solution and associated manual revisions. (See “FTR Bid Limit Increase Endorsed Under Fast Track Pathway,” PJM MIC Briefs: Jan. 11, 2023.)

Issue Tracking: FTR Auction Bid Limits

Members Committee

Consent Agenda (12:35-12:40)

As part of its consent agenda, the MC will be asked to endorse:

B. a proposed solution to implement the second phase of PJM’s hybrid resource rules, along with corresponding tariff and Operating Agreement revisions. (See PJM Releases Phase 2 of Energy Transition Study.)

Issue Tracking: Solar-Battery Hybrid Resources

C. a proposal to revise PJM’s day-ahead zonal load bus distribution factors and corresponding revisions to tariff section 31.7. (See “MIC Endorses Proposal on Hybrid Resources,” PJM MIC Briefs: Nov. 2, 2022.)

Issue Tracking: Day-ahead Zonal Load Bus Distribution Factors

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Nuclear Bill Advances in Washington House

OLYMPIA, Wash. — The House Environment & Energy Committee unanimously recommended Thursday that the full House of Representatives pass a bill to add advanced nuclear reactor technology to the alternative power sources that the state uses to replace fossil fuels.

House Bill 1584, sponsored by Rep. Stephanie Barnard (R), would add advanced nuclear to solar, wind, hydroelectric dams, landfill methane and other sources of non-fossil fuel power sources. Washington is legally required to eliminate 95% of its greenhouse gas emissions by 2050. Barnard represents the Tri-Cities, home of the 1,200-MW Columbia Generating Station nuclear plant, which produces roughly 12% of the state’s electricity.

The owner of the plant, Energy Northwest, supports the bill, as does the Grant County Public Utility District, which is considering building a small modular reactor (SMR) complex within its territory.

Each modular unit would be a mini-reactor capable of generating 50 to 300 MW. SMRs are designed to allow additional modules as needed, with 12 modules being the theoretical maximum. Compared with conventional nuclear, the concept is supposed to result in lower costs, faster construction times and more flexibility in tailoring a reactor complex to its customers’ needs.

Grant County PUD is looking at a design by Maryland-based X-energy but has not decided whether to pursue an SMR.

“We’re looking at advanced nuclear technology because of growth in our county,” Bill Clarke, a lobbyist representing the PUD, told the committee.

NuScale Power of Portland, Ore., became the first SMR developer to receive approval for its 60-MW design by the Nuclear Regulatory Commission. The company plans to submit an improved follow-up version of that design to the commission that includes increasing output to 77 MW each. The company is pursuing building its first complexes in Idaho Falls, Idaho, and Romania by the end of this decade.

Leaders from both Energy Northwest and the Tri-Cities want to attract NuScale to build at the site of two never-completed reactors next to the Columbia plant. That site has infrastructure in place to build either reactors or reactor components.

At Thursday’s committee hearing, Roger Lippman of Nuclear Free Northwest opposed the bill, saying the term “advanced nuclear technology” is not defined in the bill. He added that no advanced nuclear technology plants have begun operating in the U.S., meaning the technology does not have a proven track record.

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FERC Affirms MISO’s Seasonal Auctions, Accreditation

FERC on Thursday rejected two rehearing requests over MISO’s seasonal capacity auction and availability-based resource accreditation, clearing the way for the RTO to conduct its first seasonal auctions in April.

The commission affirmed its previous decision that the seasonal, availability-based accreditation will incentivize availability and more accurately represent when generating units contribute to resource adequacy (ER22-495).

Commissioner Allison Clements, as she did in FERC’s original order last year, disagreed with MISO’s accreditation inputs, saying it “glosses over MISO’s failure to adequately justify key details in its proposal.”

Clements zeroed in on what she called “two of the most problematic design flaws”: MISO’s selection of resource adequacy hours that allow resources up to 12 hours to be counted in its operating reserve margin calculation, and the 24-hour lead time before resources are excluded from being assumed as available during those hours.

“In defense of its position, the only explanation MISO gave is that its choice of a 12-hour lead time was better than an alternative of 24 hours, which would have included even more resources incapable of delivering capacity when needed,” she wrote in a concurring opinion. “But the Federal Power Act is not a ‘Price is Right’ showcase showdown, and the fact that a proposed rate is closer than an unjust and unreasonable option does not demonstrate it to be just and reasonable. One hundred dollars for a gallon of milk is not a fair price, and the fact that $50 is a better alternative does not make it reasonable.”

Clements said MISO’s decision to credit resources that take up to a full day to start up will lead to extending credits for resources that are ineffectual during reliability issues.

“Incredibly, while MISO’s only defense of using 12 hours as the lead time threshold for including resources in its calculation of operating margin is that doing so is more accurate than using a 24-hour lead time, it proposes to use the even-less-accurate 24-hour lead time when determining which resources get credit for delivering capacity,” she said.

FERC last year approved the grid operator’s request to conduct four seasonal capacity auctions, with separate reserve margins, and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours,” covering 65 hours during the year when resource availability is less than 25% of operating margin.

Louisiana and Mississippi regulators, Consumers Energy, Entergy (NYSE:ETR), DTE Energy (NYSE:DTE) and Alliant Energy (NASDAQ:LNT) sought rehearing of the order’s accreditation portion. They said a harsher accreditation based on risky hours that can’t be predicted with certainty will result in fluctuating accreditation values, undue penalties to generation and won’t reflect MISO supply fundamentals. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

DTE and Alliant accused the commission of “cursorily sweeping aside” concerns over accreditation instability. They said the accreditation framework could potentially cause about a “ten-fold increase in year-to-year accreditation volatility for some market participants” and could cause members to overbuild generation on the MISO system.

Entergy noted that according to the RTO’s own analysis, a quarter of all market participants’ total accredited capacity will experience a standard deviation between 7.7% and 15.5% from one planning year to the next in the spring season. Entergy said that translates into a 20% chance that a market participant’s total accredited capacity will “undergo a year-to-year change of 20%.”

The utility said a resource can experience “a significant reduction” in accredited capacity if it is unavailable during “even one or two days.” Mississippi and Louisiana agreed that the design will cause “large swings” in accreditation year over year.

Before last year, MISO accredited its thermal resources annually based on the asset’s historic three-year equivalent forced outage rates.

The commission was unpersuaded by the arguments and said the new accreditation’s benefits still stand to outweigh the small amount of aggregate volatility it introduces across planning resources’ capacity values.

FERC said the accreditation will lead to “increased accuracy, increased confidence in generator availability during high-risk hours, better coordination of resource outages and stronger incentives for resources to be available in times of need.”

The commission disagreed with a coalition of clean energy organizations that said thermal resources shouldn’t have a different accreditation framework from renewable resources. It said resource classes can be accredited using different methods.

The clean energy groups also took issue with MISO’s response should a season not have at least 65 resource adequacy hours. The grid operator will use resource performance data from other high-risk hours throughout the year as a “backfill” to ensure there are 65 resource adequacy hours.

They also said MISO’s proposal to top off the risky hours to make sure it meets a minimum 65 hours, or 3% of a season, “creates an artificial profile for these resources and assumes risk in a season during hours where there are none.” FERC responded that maintaining a minimum target of hours to base accreditation upon “mitigates the volatility concerns.”

The commission also supported MISO’s 120-day advance notice requirement for planned generator outages; a capacity replacement obligation for resources on planned outages lasting longer than 31 days; and the RTO’s plan to treat offline resources with lead times greater than 24 hours as unavailable during resource adequacy for accreditation purposes.

It resisted calls to delay the seasonal launch until the 2024-25 planning year to let market participants get their bearings in the new environment. FERC said market participants have attended stakeholder workshops that warned of the change as far back as 2019.

FERC’s decision arrives as MISO may revise the availability-based accreditation method. The grid operator wants to adjust unit-level accreditation by a capacity value determined by loss-of-load expectation rather than its existing unforced-capacity values that rely on forced outage rates.

The design would apply to all resources and require edits to the new availability-based design. MISO currently uses a unit-level effective load-carrying capability calculation based on a peak hour contribution for wind resources. (See Stakeholders Cry Foul on MISO’s Resource Accreditation Pivot.)

Clements contended that FERC violated the Administrative Procedure Act because it did not respond to arguments that many resources with nearly a full day’s startup time cannot maintain reliability when they’re offline during resource adequacy hours.

She found it “laudable” that MISO is seeking to improve “its outdated capacity accreditation framework. “

“It is clear that … today’s markets must be designed to address increasingly complex reliability challenges. Although MISO’s proposal fell short of the mark, this does not suggest that changes to MISO’s resources adequacy rules are not appropriate. To the contrary, further changes appear necessary,” she said.

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PJM EIS Announces New Hourly Clean Energy Certificates

The subsidiary of PJM that manages its registry of clean energy certificates will next month release a new product broken down by the hour in which the energy was created, the RTO announced last week.

Ken Schuyler, president of PJM EIS, said no other registry of renewable energy credits (RECs) in the U.S. has created an hourly product, but he believes it’s a road others are likely to follow to meet the needs of customers seeking increasingly granular data, particularly those striving to meet clean energy goals.

The certificates currently managed by the Generation Attribute Tracking System (GATS) that EIS operates include the generator location, emissions output, fuel source and date the generator went online. Each one represents 1 MWh and are produced based on the amount of power the facility produced in a given month.

The new credits will also include the output by date and hour.

“We recognize that customers are interested in more granular, real-time data that can be used to innovate new ways to incentivize clean energy,” Schuyler said in an announcement. “Using the unique data offered by GATS, customers can make more informed choices about their energy use.”

The more detailed certificates allow those with environmental targets to match their energy usage throughout the day to ensure the entirety of their power is provided by renewable or carbon-free generation, Schuyler said. Another application he identified is for buyers to target when they purchase credits to displace high-emitting generators during hours when marginal emissions are at their highest.

“The hourly data that we’re making available is being made available so that they can make informed choices and accomplish their strategies, whatever that might be,” he told RTO Insider.

Constellation Energy (NASDAQ:CEG) applauded the announcement, saying it enhances the ability for consumers to demonstrate that they are using carbon-free energy. 

“This advancement is enabling companies like Constellation to offer a more complete range of products that help customers meet their sustainability goals,” said Kathleen Barrón, Constellation’s chief strategy officer. “As we work toward our purpose of accelerating the transition to a carbon-free future, we can provide this critical service for customers who want more clear and accurate data on their emissions impact, including producers of clean hydrogen who must demonstrate that they are using zero-carbon energy to qualify for new federal tax credits.”

The company noted that it launched its own hourly carbon-free energy matching product last year, allowing customers to match their energy with regional carbon-free generation on an hourly basis. The new hourly certificates supplied by EIS will provide a “transparent and independent way to certify that they are meeting their clean energy goals.”

Speaking on a panel during PJM’s General Session in October, Brian George, lead of Google’s (NASDAQ:GOOGL) energy regulatory and policy engagement team, said the company was shifting to procuring clean energy when and where it’s needed, rather than focusing on the installation of additional renewable generation. In an email following PJM’s announcement, he said the hourly data is central to the company’s carbon-free energy goals. (See PJM General Session Focuses on Clean Energy Transition.)

“We welcome PJM’s announcement to implement an hourly tracking mechanism. As a buyer of electricity in PJM with a goal to power our data centers with 24/7 CFE by 2030, hourly tracking is essential. We hope other RTOs and ISOs across the country will follow PJM’s leadership,” George wrote.

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Exelon Earnings Highlight Investments to Comply with State Legislation

Exelon (NASDAQ:EXC) leadership last week charted out the company’s path to maintaining its growth targets while implementing its plans to comply with state environmental legislation.

“The Exelon team has proven it’s ready to meet the challenge of leading the nation in its energy transformation, powering a cleaner and brighter future for our customers and our communities while creating value for our shareholders,” CEO Calvin Butler said during the Feb. 14 earnings call.

Exelon reported a 27% increase in earnings for 2022, at $2.054 billion. Its fourth-quarter earnings of $432 million were nearly 40% higher than those in the fourth quarter of 2021.

The company saw 8.1% annual growth off its 2021 guidance midpoint and operating earnings of $2.27/share, exceeding guidance by 2 cents/share. The 2023 projection anticipates 5% earnings growth relative to the 2022 guidance and operating earnings guidance at $2.30 to $2.42/share.

Butler said the company completed its separation with Constellation Energy and has had a successful first year as a transmission-and-distribution-only utility.

“In 2022, Exelon showcased our ability as a pure transmission-and-distribution company to deliver on our financial and operational commitments,” Butler said. “Because of the partnership with our customers and communities, Exelon is ready to lead the energy transition to a cleaner and brighter future.”

CFO Jeanne Jones noted that the 5% growth expected this year is below Exelon’s 6 to 8% target range between 2022 and 2026. Exelon is projecting its operations and maintenance costs being $100 million higher this year, which Jones attributed to one-time costs associated with the Illinois Clean Energy Jobs Act (CEJA), as well as information technology investments, cybersecurity enhancements and taking advantage of favorable weather to engage in corrective maintenance.

Commonwealth Edison filed its first multiyear rate plan and its grid plans to the Illinois Commerce Commission under CEJA, which calls for carbon-free energy generation by 2045. The plan’s investments include bus reconfigurations, work overhead and underground infrastructure to support an anticipated 1 million electric vehicles by 2030, and converting 4-kV infrastructure to 12 kV. (See Illinois Senate Passes Landmark Energy Transition Act.)

“As Illinois progresses towards its decarbonization goals, ComEd is starting from an industry-leading position of strength,” Butler said.

ComEd has also filed with the ICC to defer collection of 35% of the 2024 rate increase until 2026 to smooth the impact for customers.

Jones said carbon mitigation contracts are projected to save ComEd customers over $3 billion in energy charges between 2022 and 2027.

The company is also preparing to submit its multiyear plan with the Maryland Public Service Commission later this month, with proposed investments in line with the state’s Climate Solutions Now Act. Jones pointed to the $50 million in school bus electrification incentives Baltimore Gas and Electric has offered Maryland school districts as the type of investments the utility is making. (See Md. Climate Bills Become Law Without Hogan’s Signature.)

“Like Illinois, Maryland’s Climate Solutions Now Act has set aggressive climate and decarbonization targets, creating an environment where utility action and investment is a key priority and for which multiyear planned frameworks are particularly well suited,” Butler said.

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CenterPoint to Invest $43B, Addressing Customer Growth

CenterPoint Energy (NYSE:CNP) said Friday it plans to increase its 10-year capital plan to $43 billion through 2030, with a focus on additional investments in grid reliability and modernization.

CEO David Lesar told analysts on an earnings call that the company has added $2.3 billion to the capex plan and identified an additional $3 billion of potential opportunities that will be folded in “when we believe we can operationally execute it, efficiently fund it, and minimize the regulatory lag associated in recovering it.”

The Houston-based utility reported fourth-quarter earnings of $122 million ($0.19/share) and year-end earnings of $1.01 billion ($1.59/share), compared to $641 million ($1.01/share) and $1.39 billion ($2.28/share) for the same periods in the previous year.

“We continue to execute well; 2022 was truly an exciting and productive year,” Lesar said during the call. “We are confident that this strong momentum will continue into the new year.”

He noted it was the 11th straight quarter CenterPoint has exceeded or met its own expectations for earnings guidance. Lesar has been CEO for the last 10 of those quarters.

The infrastructure investment will be needed. Texas has added nearly 1.1 million jobs since the COVID-19 recession, Lesar said. Houston, CenterPoint’s primary electric service region, has added 179,000 jobs and increased its population by almost 300,000 to nearly 7 million, he said.

“This is now like adding a city the size of Irvine, Calif., to our footprint in just one year,” Lesar said. “We see this trend continuing as the Texas miracle keeps humming along.

“This growth is just one of the reasons we believe we are uniquely positioned as a company.”

The company’s share price closed at $29.22 Friday, a gain of 16 cents on the day.

Entergy Takes Hit from Grand Gulf

Entergy (NYSE:ETR) on Thursday reported earnings of $106 million ($0.51/share) for the quarter and $1.1 billion ($5.37/share) for the year. That compared to $259 million ($1.28/share) for 2021’s fourth quarter and $1.12 billion ($5.54/share) for the year.

The results included a $551 million charge, $413 million after tax, for System Energy Resources Inc. (SERI), the Entergy subsidiary that owns the Grand Gulf Nuclear Station in Mississippi. FERC in December issued two orders involving the plant’s customer rate impacts. The orders addressed a series of uncertain tax positions that SERI took.

The New Orleans-based company has begun issuing refunds to ratepayers. It reached a $300 million settlement with the Mississippi Public Service Commission last June.

“We still believe that a global settlement with the remaining retail regulators on terms similar to the agreement with the MPSC would be in the best interest of all parties,” Entergy CEO Drew Marsh told financial analysts during the quarterly conference call. “It would resolve disruptive litigation uncertainty for SERI and our stakeholders, including our regulators, accelerate meaningful value to customers, avoid costly and unnecessary third-party litigation fees and allow all parties to move forward with fewer distractions.”

Entergy’s earnings exceeded Zacks Investment Research projections of $0.45/share. Entergy’s share price ended the week at $109.42, up $1.87 from Wednesday’s close.

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FERC Denies RENEW Northeast Complaint

FERC on Thursday dismissed a complaint from RENEW Northeast that had alleged that ISO-NE has “undue preference” for gas generators in its capacity accreditation and operating reserve rules (EL22-42).

The complaint from March of last year argued that ISO-NE doesn’t adequately take into account the uncertainty of natural gas supply in the region, particularly in winter, and that it therefore harms almost every other type of generation. (See Renewable Groups Challenge Gas ‘Preference’ in ISO-NE Rules.)

The complaint has been closely watched in New England, and FERC received many comments on both sides of the argument.

Ultimately, the commission found that RENEW failed to meet its burden under Section 206 of the Federal Power Act to show that the existing tariff is unjust and unreasonable.

Specifically, FERC wrote in its dismissal order that RENEW “failed to establish that gas-only resources are not similarly situated to generators with fuel on site.”

As for the complaint’s points on operating reserves, FERC noted that, contrary to what RENEW claimed, the ISO-NE tariff doesn’t require any resource to “have a known and measurable fuel supply and verifiable means of delivering upon real time dispatch.”

But in dismissing the complaint, FERC also called on ISO-NE to step up.

“We urge prompt action by ISO-NE on reforms, including capacity accreditation if deemed appropriate, to address these reliability concerns,” the commission wrote, adding that it is planning another forum on winter reliability issues in New England for June.

ISO-NE spokesperson Matt Kakley emphasized that the grid operator is continuing to work on updating its capacity accreditation rules through the stakeholder process.

“We’re pleased that FERC dismissed this complaint. To date, the region’s markets, including the capacity market, have achieved their primary reliability objective, but an overhaul of the capacity accreditation process is critically important as the region transitions to the future grid,” he said in a statement.

“To that end, ISO New England and stakeholders have been working on this issue for more than a year, with plans to file a proposal with FERC later this year. With this complaint formally dismissed, ISO New England and others can now engage with FERC commissioners and staff, benefiting from their views and expertise as the region navigates this important process.”

Clements’ Concurrence

Commissioner Allison Clements went a step further than the rest of the commission. In a forceful concurrence, she wrote that she believes the ISO-NE tariff is in fact unjust and unreasonable, even though the commission had to dismiss RENEW’s complaint because of what she called a “pleading error.” And she called on FERC to take action itself.

“In the face of clear evidence that ISO-NE’s rules fail to ensure the supply of resources when they are most needed, in my view the commission has a duty to take action to ensure grid reliability,” Clements wrote.

Clements noted that everyone, including ISO-NE, agrees that the region faces gas delivery constraints that can threaten energy security, especially during extended extreme winter weather.

“Given this apparent agreement that ISO-NE’s rules are failing to assess the reliability of resources when they are most likely to be needed, in my view the Commission has a duty to fix the problem via action pursuant to section 206 of the Federal Power Act,” Clements wrote. “We cannot stand idly by as the region heads toward yet more winters for which it is not adequately prepared.”

And she also suggested that she is wary of what ISO-NE might put forward in its formal capacity accreditation process.

“In my time at the commission, thus far it has accepted almost every significant capacity accreditation proposal put forward by an RTO or regional framework,” she wrote. “My view has been that some of these proposals met the requirements of the Federal Power Act, while others did not.

“As these decisions mount … they contribute to a slow but steady erosion of the commission’s bedrock legal standard that rate proposals must be just and reasonable and not unduly discriminatory,” Clements wrote.

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FERC Approves PJM Quadrennial Review

FERC last week accepted a set of revisions to PJM’s tariff that the RTO proposed through its Quadrennial Review of the parameters underlying its Reliability Pricing Model (RPM) auctions (ER22-2984).

The Feb. 14 order accepted all the changes sought by PJM, sanctioning a market design with a steeper variable resource requirement (VRR) curve intended to procure a smaller amount of capacity hewing closer to the reliability requirement. The new paradigm also switches the reference resource used to determine the cost of new entry (CONE) from a combustion turbine to a combined cycle generator.

“This Quadrennial Review proposal was developed with an unprecedented level of stakeholder input and appropriately reflected stakeholder priorities,” PJM spokesperson Jeff Shields said in response to the order. “The new VRR curve is an improvement on the prior VRR curve, as it achieves a better balance between reliability and cost by procuring resources based on the reliability standard, thus meeting reliability requirements at a reasonable cost while incentivizing investment in new generation resources.”

Steeper VRR Curve

Pointing to market simulations conducted by the Brattle Group, PJM said the existing VRR curve over-procures capacity and results in an average loss-of-load expectation (LOLE) of one in 17 years, which it states is “significantly greater” than the target of one in 10. The new market design was simulated by Brattle to produce a LOLE of one in 14.

The new shape shifts the foot of the curve, the lowest point, about 2.2% to the left of the reliability requirement to “help prevent costly impacts of overestimations of net CONE, which would result in more reliability than expected,” PJM said in its filings.

PJM also changed the calculation for setting the capacity price cap, the highest point of the curve, to be set at the greater of the gross CONE or 1.75 times net CONE. The shift away from the current cap set at 1.5 times net CONE is intended to address the possibility that market conditions could change in the gap between the Base Residual Auction’s (BRA) and the delivery year and result in an underestimation of net CONE and therefore an under-procurement of capacity.

The PJM Power Providers (P3) protested the changes, saying that the steeper curve, combined with the other changes the RTO proposed, would result in increased volatility and compound the price impacts of each market design change. (See PJM Defends Quadrennial Review Parameters from Generator Protests.)

The Independent Market Monitor noted in its comments that the proposal moves closer to its recommendation of rotating the curve halfway toward a vertical demand curve, which would have created a much steeper curve. The Monitor’s analysis found that the recommendation would have reduced the 2023/24 BRA’s revenues by $406 million, or 18.5%. (See IMM Offers Mixed Review of PJM Quadrennial Review Docket.)

Forward-looking EAS Offset Calculation

The market design changes also include switching from using historical data to calculate energy and ancillary services (EAS) revenues to a forward-looking approach to calculating the EAS offset.

The change was supported by several environmental and public interest groups in a joint filing stating that a forward-looking EAS offset would be more responsive to an evolving resource mix, fuel prices and future market conditions.

The Monitor also supported the change, stating that the proposed approach reflects how investors evaluate the market and avoids overstated capacity market prices stemming from an EAS offset being based on historically low prices in the PJM markets as current and forward-looking energy prices have increased significantly.

In its protests, P3 said the use of futures prices would increase market uncertainty and volatility. By using proprietary data and models in its calculations, P3 also said that the proposal lacked transparency and limited market participants’ ability to estimate how future EAS revenues would be determined.

In accepting the forward-looking approach, the commission wrote that it relies on the same data developers use to assess project viability and that prices from liquor futures markets produce prices reflecting future conditions.

“We find that PJM’s proposed use of futures prices to calculate the EAS offset is just and reasonable because the record indicates that futures prices better reflect PJM market participants’ expectations of future market conditions as compared to historical electricity prices,” the commission said. “Indeed, P3 provides no evidence that market participants themselves use historical prices to predict future prices. PJM, on the other hand, supports its claim that market participants use futures prices.”

The commission also said that this was in line with an “almost identical” that it approved in 2020 (EL19-58).

PJM had previously sought to shift to using futures data as part of a 2019 filing revising its reserve markets and received FERC approval the following year, but the commission reversed itself in 2022. In overturning the previous order, the commission said its reversal of the reserve penalty factor and operating reserve demand curve (ORDC) “undermined the fundamental basis” for its determination that the historic offset was unjust and unreasonable. (See FERC Reverses Itself on PJM Reserve Market Changes.)

Change to Combined Cycle Reference Resource

Shifting away from its longtime usage of combustion turbines as the reference resource, PJM proposed to use a combustion cycle generator as the resource type that is most likely to be constructed to meet a capacity shortfall in the future. The RTO noted that the last combustion turbine built in its footprint was in 2018, and the Monitor wrote that no “significant level” of capacity has been installed since 1999.

P3’s protest stated concerns that using a combined cycle would come with a higher and more variable EAS offset. It said that higher profits in those markets could lead to a lower net CONE, lower relative capacity prices and ultimately less capacity clearing even if a higher supply is needed.

“Based on the record as a whole, we find P3’s concerns to be overstated,” FERC said. “As Brattle explains, perverse incentives will not be substantially different for combined cycle plants than for combustion turbines because both combined cycle plants and combustion turbines are usually operating as load approaches peak load, which is when energy prices are more sensitive to supply conditions.”

Amortization Period

The commission also overruled a protest from J-Power USA stating that the amortization period used in the calculation of gross CONE doesn’t take into account legislation that would shorten the lifespan of a generator, namely Illinois’ Climate and Equitable Jobs Act (CEJA).

The company pushed for a shorter amortization in the ComEd locational deliverability area (LDA) to reflect the requirement that generators be carbon free by 2045, which the protest said would result in the early retirement of gas generators, including the combined cycle unit reference resource.

The commission noted that PJM stated it would be inappropriate to change the period for the ComEd transmission zone without changing the parameters for the rest of the CONE area and that CEJA contains a carveout to allow generators to continue operating outside the emissions requirement if deemed necessary for reliability.

Danly and Christie Reluctantly Concur

Commissioner James Danly wrote that while he is in agreement that the Quadrennial Review filing meets the requirements of Federal Powers Act Section 205, he believes that the protests to its provisions show that the commission should consider a broader examination of PJM’s capacity market.

“The time is ripening for the commission to investigate whether the PJM rate construct (including the capacity market) is just and reasonable and not confiscatory,” he wrote. But in this section 205 proceeding, I agree — reluctantly — that PJM has made the required showing that these piecemeal proposals are just and reasonable.”

Commissioner Mark Christie also said that the larger functioning of the capacity market was the “elephant in the room” as the commission examined the Quadrennial Review.

“Moreover, we cannot ignore the events of last Dec. 24 and 25: Winter Storm Elliott,” Christie said. “One of the common criticisms over the years has been that the PJM capacity market procures too much capacity, yet during at least two recent extreme weather events — the polar vortex of 2014 and Winter Storm Elliot last December — PJM reportedly came very close to ordering rotating outages. … My point in this concurrence is not to analyze, favor or criticize earlier changes to the capacity market construct or propose new changes; my point is a larger one: that these events raise important broad questions about this capacity construct’s efficacy.”