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November 5, 2024

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ISO-NE Projects Decrease in Gas, Increase in Coal and Oil for 2032

ISO-NE projects an approximate 47% decline in gas generation for the year 2032 compared to current levels but expects coal and oil generation to increase by 45% to meet winter peak loads, the RTO told its Planning Advisory Committee on Tuesday.

Despite the expected winter increase in coal and oil generation, ISO-NE anticipates emissions declining across all months by 2032, with the largest emissions reductions coming in the spring, summer and fall. ISO-NE projects annual emissions being nearly half of 2021 levels, declining from about 30 million tons of carbon per year to 16 million tons.

These findings are part of the RTO’s ongoing Economic Planning for the Clean Energy Transition pilot study. The study takes into account the increase in peak load due to electrification projected by ISO-NE’s 2023 Capacity, Energy, Loads and Transmission report. (See ISO-NE Increases Peak Load Forecasts.)

“Additional PV and wind resources beyond what is already in the model may help alleviate demand for dispatchable generation, but the needed volume of energy is significant,” said Benjamin Wilson of ISO-NE. “Some additional energy storage will likely be needed to shift the energy from when it is produced to when it will be needed.”

Wilson said the results indicate overall lower production costs and locational marginal prices due to the influx of zero-marginal-cost energy resources replacing gas generation.

“The system may experience an increase in reliance on stored fuels (LNG, oil, and coal) in the winter despite the new wind, solar and energy storage resources,” Wilson added.

The results contain limits: The study did not model generator outages and includes generators that did not receive capacity supply obligations in the latest Forward Capacity Auction and may retire prior to 2032. This includes the Merrimack Station, the last coal-fired generator in New England. The study also assumes continued operations of the Everett LNG import terminal for 2032.

Monthly emissions in 2021 compared to 2032 min and max scenarios. | ISO-NE

“A reduced LNG capacity would lead to an increased demand on other stored fuel resources,” Wilson said.

Transmission Planning

Also at the PAC, Dan Schwarting, manager of transmission planning at ISO-NE, presented initial high-level takeaways from the RTO’s 2050 Transmission Study, looking at meeting the transmission needs of the region for 2035, 2040 and 2050. ISO-NE expects a draft of the study to be ready to present to the PAC in November.

Schwarting told the committee early results indicate relatively small reductions in the projected 2050 winter peak load are associated with outsized reductions in transmission costs.

A 10% reduction of ISO-NE’s initial 57-GW winter peak “snapshot” for 2050—which represents the electrification of nearly all the region’s heating using existing technology—would be associated with a roughly one-half to one-third reduction in transmission costs, Schwarting said.

Despite uncertainty in predicting future load concentrations and generator locations, Schwarting said some high-likelihood upgrades could be pursued in the near term, including increasing capability for north-south transfer and Boston imports.

“Investment in addressing these concerns may be prudent regardless of exact generator locations and load distribution,” Schwarting said.

To meet the future needs for north-south transfers and Boston imports, Schwarting laid out four potential pathways: prioritizing rebuilds of existing lines, building new 345-kV overhead transmission, building new HVDC transmission lines or building an offshore grid that would enable power transfer between states and regions.

“In many parts of New England, addressing concerns by rebuilding existing lines for higher capacity is clearly more cost-effective and feasible,” he said, adding that using this approach to address all regional needs could end up being more expensive than the alternatives, and this path could not scale up to meet a 57-GW peak demand.

Schwarting highlighted some potential benefits of an offshore grid, including the ability to move power between interconnection points when capacity is not taken up by wind power.

“For example: In summer daytime peak snapshots, wind is assumed to be at 5% output. The remaining 95% of cable capacity is available to transfer power from one point of interconnection to another,” Schwarting said. “Beyond what is modeled in the 2050 Transmission Study, these grids could be expanded to include wind farms connecting to New York, PJM or other neighboring areas.”

Schwarting emphasized that providing a full cost/benefit analysis of an offshore grid is beyond the scope of the study, which will look only at approximate costs and a limited set of benefits.

“While significant research and development towards offshore transmission has been performed in Europe, meshed offshore HVDC systems are not yet in use commercially,” Schwarting added, noting the National Renewable Energy Laboratory is conducting a two-year study into Atlantic offshore wind transmission that will consider the potential for an offshore grid.

Asset Condition Projects

Eversource, National Grid, and Avangrid presented on several asset condition projects totaling over $100 million:

    • Eversource expects to spend about $31 million on structure replacements and optical ground wire installations on one 115-kV line and two 345-kV lines in Connecticut, citing age-related issues including woodpecker damage, cracking and splitting, and damaged insulators and deteriorated steel hardware. The expected in-service dates for the projects range from late 2024 to early 2025.
    • National Grid proposed spending about $6 million to replace five 69-kV and six 115-kV Oil Circuit Breakers at the Northboro Road Substation in Northboro, Mass.
    • Avangrid increased its cost estimate for its 115-kV Derby Junction to Ansonia Line Rebuild Project, proposing to spend $71 million to rebuild the line, nearly doubling the cost compared to its 2021 estimate of the rebuild. The company said the rebuild would extend the life of the line by at least 50 years.
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Higher Water Heater Efficiency Standards Sought

The U.S. Department of Energy is proposing efficiency standards it says will save Americans billions a year on the operation of their water heaters and eliminate millions of tons of carbon dioxide emissions.

The proposal announced Friday would mandate heat pump technology in the most common-sized electric water heaters and mandate improved condensing and other technology in fossil fuel-burning units.

The department is mandated by Congress to make periodic updates in efficiency requirements; this is the 18th it has issued so far in 2023. The last update of water heater standards was in 2010.

The agency said it followed recommendations from two major water heater manufacturers, the Consumer Federation of America and a variety of stakeholders as it put together this new proposal. If adopted on the timeline DOE proposes, it would take effect in 2029.

Warming up water for household purposes accounts for about 13% of annual residential energy use.

The actual consumer benefit of the new standard would depend on the cost of fuel or electricity and on the speed of replacement of old technology with new. But DOE estimates that over the course of 30 years, the proposed standards could save Americans $200 billion and reduce CO2 emissions by 500 million metric tons.

That breaks down to a savings of $1,868 over the lifespan of an electric heat pump water heater compared with a traditional electric resistance unit, the department said. Further savings accrue with credits, rebates and other incentives offered through the Inflation Reduction Act.

The rule also would boost minimum efficiency ratings for tankless and storage water heaters that burn oil or gas, again by relying on technology improvements.

In total, DOE estimates the proposed rule would reduce energy used by water heaters by 21% and provide a $2.8 billion-a-year health benefit.

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NYISO Addresses NYC Near-Term Reliability Need

ALBANY, N.Y. — NYISO took stakeholder questions on its statement about the predicted reliability shortfall in New York City, during the Electric System Planning Working Group meeting on Tuesday.

“The short-term reliability need is primarily driven by a combination of forecasted increases in peak demand and the assumed unavailability of certain generation in New York City affected by the peaker rule,” read the ISO’s statement.

NYISO Reliability Studies Manager Keith Burrell explained the ISO was required by tariff Section 38.3.6 to explain why it was soliciting “a regulated non-generation short-term reliability solution solely from a responsible transmission owner,” which became necessary after its second quarter short-term assessment of reliably report identified that NYC could have up to a 446 MW marginal reliability deficiency by 2025. (See NYC to Fall 446 MW Short for 2025, NYISO Reports.)

“The reason the need observed in our Q2 STAR wasn’t observed in prior STAR reports was primarily due to the updated demand forecast,” said Burrell, referring to how planned fossil fuel plant retirements were included for the first time.

“We identified in our 2022 RNA [reliability needs assessment] that if demand forecast increased by as little as 60 MW there was the potential for a reliability need,” he added, “looking now at NYC forecasts, the demand went up by 294 MW when considering the baseline statewide coincident peak for estimated needs.”

Howard Fromer, who represents Bayonne Energy Center, asked if NYISO was measuring the need in MWs or MWhs.

Burrell responded, “it’s a little bit of both, when we identify a need it’s going to get the MW deficiency, but we also do some investigation to get an idea of what the hour of the need can be.”

Fromer then asked whether NYISO would entertain solutions that were less than the 446 MWs of identified need, and if some combination of regulated solutions would be considered.

“Ultimately, the solutions selected need to fully address the need but can come from multiple different options,” Burrell said. NYISO staff referred to Section 38.6.1 of the tariff to clarify what constitutes a viable and sufficient solution.

Mark Younger, president of Hudson Energy Economics, asked NYISO to further investigate statewide reliability shortfall scenarios, pointing out that the Q2 STAR also identified that at extreme loads the entire state could see marginal deficiencies. “It would be good to have some of these [scenarios] chased down before we finalize the next round of analysis,” he said.

Doreen Saia, an attorney with Greenberg Traurig, warned NYISO that whatever solution it chooses, “there are certain actions that can’t be undone,” referring to how decisions to decommission Indian Point nuclear power plant, in hindsight, seem regrettable given the state’s current reliability needs.

NYISO asked for any further comments or questions be sent to DeveloperSolution@nyiso.com before July 28. All notes will be posted online.

NYISO plans to post the third quarter STAR by Oct. 13.

NYC PPTN

NYISO also gave a status update to the ESPWG/TPAS on the public policy transmission need for New York City, which was called by the state’s Public Service Commission to deliver at least 4,770 MW of offshore wind from Long Island. (22-E-0633).

The PSC ordered another Zone J-to-K OSW transmission solution to help meet state energy goals like producing 9,000 MW of OSW by 2035, using the momentum that was built after NYISO’s board selected a project to fulfill the Long Island PPTN that called for at least 3,000 MW of export capability. (See New York PSC Calls for More Transmission for Long Island OSW.)

The NYISO has begun conducting baseline assessments for the NY PPTN to determine the actual need and what solutions are needed to meet that need. This process is followed by a 60-day window where developers can propose their own transmission solutions.

NYISO tentatively will start soliciting solutions in the first quarter of next year with the goal of the PPTN being completed by the third quarter of 2025.

NYISO promised it was actively coordinating with state agencies and other relevant parties, such as the Department of Public Service, Con Edison and the New York State Energy Research and Development Authority, in response to questions from stakeholders about the ISO’s engagement with these groups.

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NextEra Energy Says Solar Supply Crunch Has Eased

NextEra Energy on Tuesday discussed the continued growth of its renewable energy portfolio in a positive second-quarter 2023 earnings report.

Subsidiary Florida Power & Light placed 225 MW of new solar capacity into service in the quarter, bringing its total for the first half of the year to nearly 1,200 MW, while subsidiary NextEra Energy Resources added 1,215 MW of solar, 150 MW of wind and 300 MW of storage.

“As we indicated in our recent 10-year site plan, solar continues to be the lowest-cost alternative for our customers,” NextEra Energy Chief Financial Officer Kirk Crews said in a conference call with financial analysts.

The challenges surrounding solar power development in 2022 appear to have subsided, he added: “After a period of underlying commodity price inflation, supply chain disruption and trade policy risk premiums, we are finally seeing signs of stability.”

CEO John Ketchum said: “All those ’22 projects that got delayed into ’23 are now starting to go into commercial operation. That’s really good news.”

NextEra Energy has announced intentions to decarbonize its operations, and Crews said Tuesday that remains the plan.

“We believe renewables remain economically attractive to alternative forms of generation,” he said. “Today, we have a pipeline of roughly 250 gigawatts of renewables and storage projects in various stages of development. This includes projects in early stage diligence and our current backlog and is supported by roughly 145 gigawatts of interconnection queue positions.”

This last point is important, Ketchum said.

“I would challenge you to find anybody in the industry that has even close to that number of projects with interconnection capacity,” he told an analyst during the Q&A portion of the call. “Given the demand we’re seeing in the market, if you have a site ready to go with interconnection capacity, that’s the hard part. Finding the customer right now is not the hard part.”

NextEra Energy signed its first contract for a standalone battery energy storage facility co-located with a wind farm in the second quarter, Crews said, and expects to use storage to further monetize its 29 GW renewables portfolio.

Ketchum said this strategy change with storage is possible because of financial changes — investment tax credits under the Inflation Reduction Act — and because of market changes.

“We are starting to see an opportunity, particularly in MISO and SPP, in ERCOT, where capacity values and reliability are being priced higher than … we’ve seen them in the past, given some of the shortfalls that they have in those markets and that just happens to coincide with where most of our wind is,” he said.

Ketchum also emphasized that NextEra’s wind portfolio is not exposed to the highly publicized quality control problems afflicting some turbine manufacturers.

“We do almost all of our business with GE,” he said. “We have done a little bit with Siemens, and I know there’s been some press on Siemens recently. We don’t have any of the Siemens Gamesa turbines in our fleet. I just want to make that very clear.”

During Tuesday’s call, the executive team also discussed second-quarter financials for NextEra Energy Partners LP.

The company completed acquisition of 690 MW of wind and solar assets in the second quarter, pushing its renewable portfolio past the 10 GW mark, but it also ran into one of the limits of wind power: varying wind speed.

The second quarter of 2022 saw the strongest wind in 30 years, 112% of the long-term average. The second quarter of 2023 saw the weakest wind in 30 years, just 86% of the long-term average.

Adjusted EBITDA generated by existing projects declined by approximately $99 million, though new projects and other revenue canceled much of that loss.

NextEra Energy Partners’ stock closed down 4.07% in trading Tuesday. NextEra Energy stock dropped 0.19%.

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Industry Cool on Revised Winter Weather Standard

The standards development team (SDT) revising NERC’s cold weather standard has more work ahead of it after industry respondents put the freeze on their latest proposed revisions with a negative segment-weighted vote of more than 56%.

The comment and formal ballot period for EOP-012-2 (Extreme cold weather preparedness and operations) — and its implementation plan — closed Thursday. The revised standard received 101 votes in favor from members of the selected ballot body, while 141 voted against it; 31 abstained, and 28 did not respond.

EOP-012-2 is intended to revise EOP-012-1, which FERC approved in February along with EOP-011-3 (Emergency operations). (See FERC Orders New Reliability Standards in Response to Uri.) Both standards were created by Project 2021-07 in response to the recommendations in FERC and NERC’s joint inquiry into the 2021 winter storm that nearly led to the collapse of the Texas Interconnection. They require generator owners (GOs) to implement several measures to prevent their units from freezing during extreme cold weather events.

In its order, the commission criticized EOP-012-1 for including “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods.” It directed NERC to clarify these issues while adding a deadline for completing corrective action plans and a shorter grace period for GOs’ implementation than the five years originally given. After the SDT for Project 2021-07 revised the standard, NERC’s Standards Committee approved its submission for comment and ballot in a special call last month.

Respondents Call Revisions Unclear

In addition to giving their approval on the overall standard, respondents also addressed the SDT’s questions about specific language and requirements incorporated into EOP-012-2. These included:

    • whether the proposed definition of generator cold weather constraints — technical, operational or economic limitations that would prevent GOs from implementing freeze protection measures — provided the clarity the FERC order required;
    • whether the standard meets FERC’s recommendation that GOs account for the cooling effects of precipitation in their temperature data; and
    • whether the two timeframes proposed in the standard for corrective action plans — 24 months for addressing existing equipment or freeze protection, and 48 months for implementing new equipment or freeze protection — are appropriate.

Responding to the first question, Thomas Foltz of American Electric Power said the proposed definition of “commercial constraint” still lacks clarity. The standard — which states that a commercial constraint exists when implementing freeze protection would result in the unit not being in service at the time of evaluation — leaves open the question of what utilities should do about equipment reaching the end of its life, Foltz said. That could leave utilities that decide not to implement expensive modifications on nearly retired units open to the accusation of “choosing economics over reliability.”

Foltz suggested revising the definition to include measures that “require unreasonably expensive modifications [or] significant expenditures on equipment with minimal remaining life.”

Regarding the requirement to account for precipitation in temperature data, Robert Follini of Avista said the standard would require utilities “simply … to perform a wind chill calculation, with an ambiguous 20-mph wind speed.” Follini pointed out that because “some regions or facilities are more protected from wind effects than others, and there is no direct correlation between extreme cold weather temperatures and wind,” the requested number likely would have little relevance to utilities’ practical winter preparations.

Finally, Donald Lock of Talen Generation objected to the timeframes for corrective action plans, saying “it is impossible to fully understand what it is that a generator owner is being asked to do at this time” because of ambiguity in the other requirements of the standard and the large number of generating facilities and units with which an entity might have to deal.

He said that while some of NERC’s other standards require similar timeframes, those typically refer to a much smaller number of units and a much smaller scope of action. Lock concluded that it isimply is not possible to say with certainty how long a retrofit campaign involving an entire generation fleet might take, and therefore the inclusion of such a requirement would be a mistake.

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NJ Sues as NYC Congestion Scheme Takes Form

New York City transit officials began working to implement their controversial congestion pricing scheme last week as New Jersey filed a lawsuit seeking to block it.

The Metropolitan Transportation Authority’s Traffic Mobility Review Board (TMRB), the six-member panel that will issue a recommended tolling structure, held its first meeting July 19 but did not make any decisions on the Central Business District Tolling Program.

The CBDTP, designed to reduce pollution and generate funds for mass transit and climate projects, received federal approval in May. (See NYC Congestion Pricing Plan Gets Federal Go-ahead.) Passenger cars entering Manhattan below 60th Street could be charged as much as $23 and trucks $82 during peak hours.

On July 21, New Jersey Gov. Phil Murphy (D) announced that his administration filed a lawsuit seeking to block the tolling scheme, blasting the federal government and the city for moving ahead on a policy that directly impacts New Jersey but is being implemented without its involvement.

“After refusing to conduct a full environmental review of the MTA’s poorly designed tolling program, the FHWA [Federal Highway Administration] has unlawfully fast-tracked the agency’s attempt to line its own coffers at the expense of New Jersey families,” Murphy said.

Murphy alleges that the government did not conduct a proper environmental review of the CBDTP, violating both the National Environmental Protection Act and the Clean Air Act.

Officials in the outer boroughs, fearing the plan could increase their own traffic, also have been unhappy. “If this plan goes forward, residents of Brooklyn, Queens, the Bronx and Staten Island will be treated as tourists in this city, and not equal citizens,” Staten Island Borough President Vito Fossella said at a briefing. “To sit here and then say to the people of Staten Island that you’re going to pay more, and your air quality’s going to be worse, doesn’t make any sense.”

The TMRB said 122 types of toll exemptions have been requested, including for “parents,” “artists” and “passenger cars.”

John Samuelsen, international president of the Transport Workers Union, received applause at the board meeting after saying the proposed nighttime carve-out, which would exempt tolls from midnight to 4 a.m., would hurt shift- and low-income workers.

John Durso, president of the Long Island Federation of Labor, also was concerned about those with low incomes. “If I get hit twice, once when I come in and once when I come home, and I am not making thousands of dollars, then that’s either taking food out of my kid’s mouth or paying my rent,” he said. “You can’t understand what it does to you when you’re pinching pennies.”

The MTA said about 700,000 vehicles enter the Central Business District daily, reducing average traffic speeds to only 7 miles per hour. “Congestion is bad for the economy, the environment and the quality of life for people who live in the CBD,” it said.

The agency has proposed providing discounts or tax credits to low-income residents. It said some proceeds could accelerate the replacement of diesel trucks with lower-emission vehicles and expand electric truck charging infrastructure.

The agency said similar programs in Stockholm and London reduced carbon dioxide emissions by 10-14% and 20%, respectively. But London’s program also has been controversial, with some blaming it for Labor’s poor results in elections last week.

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Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices

BURIEN, Wash. — Washington’s Democratic leaders last week struck back at critics who blame the state’s 6-month-old cap-and-trade program for producing the highest gasoline prices in the U.S.

That criticism came after Washington this month posted average pump prices of $4.959/gallon, far exceeding the national average of $3.54 and surpassing other expensive markets in the West. Soaring prices have prompted cap-and-trade opponents to criticize the program’s architects for not anticipating that oil companies would pass on to their customers the costs of buying carbon allowances. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

But on Thursday, Gov. Jay Inslee and Democratic legislative leaders counterattacked during a press conference in the Seattle suburb of Burien, accusing oil companies of taking advantage of cap-and-trade to gouge consumers.

“They are not just passing [the costs] on, they are padding their profits,” Inslee said at a Highline Public Schools transportation depot with four electric school buses in the background.

At the conference, Inslee’s office unveiled figures showing that Shell’s profits increased from $3.2 billion in the first quarter of 2021 to $9.6 billion during the same period this year. Over the same period, Exxon Mobil’s profits grew from $2.7 billion to $11.4 billion and Chevron’s profits jumped from $1.4 billion to $6.6 billion.

That equals a roughly $20 billion increase in profits over two years for the three companies.

“I can tell you that the gas and oil industry is not going bankrupt,” Inslee said.

During the conference, Democratic state lawmakers revealed they plan  to introduce a bill next January to force oil companies to open up their finances to show if they are gouging gasoline customers while misdirecting the blame on the cap-and-trade system. Sen. Joe Nguyen (D) said he believes oil companies are raising prices long before they actually have to pay cap-and-trade auction prices.

Another bill could address any gouging discovered by the state, Nyugen and House Majority Leader Joe Fitzgibbon (D) said.

Inslee speculated that California’s efforts to force transparency on the oil industry in light of that state’s cap-and-trade program has led the industry to put increased economic pressure on Washington, whose second-in-the-nation cap-and-trade program went into effect early this year.

In the state’s first two carbon allowance auctions, prices reached $48.50/metric ton in February and $56.01 in May. Between the two auctions, Washington sold more than 17 million allowances. The auctions have raised almost $300 million for fiscal 2024, which began July 1, and $557 million for fiscal 2025, which still has three more quarterly auctions to come.

The revenues have far exceeded government projections.

Critics Strike Back

The oil industry and Republican legislators slammed Inslee after his conference Thursday.

Sen. John Braun, leader of the Senate Republican Caucus, said the conference was “a blatant attempt to scapegoat one of his favorite boogeymen, which is the oil industry.”

“It is patently ridiculous to assume the oil companies would just absorb the hit from the governor’s ‘Cap and Gouge’ plan,” Braun said in a statement. “The simple truth is that companies pass increases in their overhead on to their customers through higher prices — just as small business and gig workers pass along increased costs from taxes and regulations to their customers in the form of higher prices.”

“The governor’s and my Democratic colleagues were simply less than transparent in 2021 about the obvious consequences of their carbon-pricing scheme,” said Sen. Lynda Wilson, the Republican caucus’s budget leader. “They knew full well how this would raise the cost of gas, which is part of the agenda to push people away from internal-combustion engines and into either electric vehicles or public transit.”

In a separate written statement, Catherine Reheis-Boyd, president of the Western States Petroleum Association, said: “Rather than ‘strategically misrepresenting’ the issue to the public, the governor and lawmakers can help consumers and business in the state by working with us to fix the cap-and-trade program. They claimed the program would cost ‘pennies,’ but Washington’s consumers are now paying 50 cents per gallon for just the cap-and-trade program. In total, the state has collected more than $850 million from just two auctions, and there are three more ahead this year.  It’s time for the political rhetoric to end and the real work to rein in the skyrocketing costs of this regulation to begin.”

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NYC Housing Authority Wants a 120-Volt Stove Brought to Market

The nation’s largest public housing authority is trying to jumpstart development of lower-voltage cooking equipment so more of its half-million residents can switch away from gas stoves.

The New York City Housing Authority said Monday it expects this autumn to launch the Induction Stove Challenge, which will call on appliance manufacturers to design and build energy-efficient stoves that can operate on 120-volt/20-amp circuits.

Induction stoves typically operate on 220 volts and 40 or even 50 amps.

NYCHA’s 177,569 housing units typically are equipped with a gas stove and 120-volt line. Upgrading the electric wiring would be impossibly expensive, even if tens of billions of dollars’ worth of deferred maintenance costs had not already accrued in the authority’s 2,411 buildings.

NYCHA wants to replace gas ranges so residents can benefit from indoor-air quality improvements, and as part of larger building decarbonization efforts.

NYCHA is joining with the New York State Energy Research and Development Authority and New York Power Authority on the initiative. They will establish performance criteria and product specifications for the induction stoves, then expect to issue a request for proposals this year, and hope to select one or more manufacturers to design and test the new ranges.

Once testing is complete, NYCHA plans to pilot these lower-voltage stoves and induction-capable cookware in 100 units.

Eventually, NYCHA wants to remove gas stoves from all the buildings it owns, but initially it will aim for 10,000 apartments. It hopes this will be a broad-enough scale that other building owners and will see induction cooking as an affordable option and manufacturers will see the potential for a larger market.

To help build that demand pipeline, NYSERDA has hired the Building Decarbonization Coalition to engage other states and property owners on the project.

The Induction Stove Challenge follows a demonstration project that put induction stoves in 10 units of a NYCHA building in the Bronx.

The stoves were a hit with the residents, and indoor air quality improved. But the effort demonstrated the site’s limits, as well.

The appliances had to be dispersed throughout the building so as not to overload the circuitry — once one apartment got an induction stove, no units directly above or below could get one.

That’s why NYCHA is excited about the possibility of running induction stoves with the standard 120-volt wiring.

“If energy-efficient induction stoves can be redesigned to function in NYCHA buildings,” NYCHA CEO Lisa Bova-Hiatt said in a news release, “it sets an amazing precedent for what can be done with existing infrastructure, some forward thinking, and the necessary funding.”

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DC Circuit Asked Again to Rule on NYISO’s 17-Year Amortization

The New York Public Service Commission on Monday petitioned the D.C. Circuit Court of Appeals to review FERC’s approval of NYISO’s proposal to use a 17-year amortization period in capacity auction demand curves (ER21-502).

NYISO proposed to move from a 20-year amortization period — the assumed time that a hypothetical peaking plant is expected to be operational — to 17 years in response to state legislation that set strict net-zero requirements that are forcing fossil plants to retire sooner.

After rejecting it twice previously, FERC accepted the ISO’s proposal in May on remand from the D.C. Circuit. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.) The commission’s rejection had been challenged by the Independent Power Producers of New York.

“The unjustified shortening of the amortization period will needlessly increase capacity auction charges by hundreds of millions of dollars,” the PSC said. The commission’s decision “must be reversed because it fails to provide the requisite ‘reasoned analysis.’”

The ISO’s revisions were part of a suite of changes called the demand curve reset, which altered the assumptions and scope for capability years 2021/22 through 2024/25 to predict the volume of megawatts needed to meet demand.

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PJM Updates Risk Analysis; Stakeholders Present Revised CIFP Proposals

Stakeholders discussed new proposals to revise PJM’s capacity market and discussed updates to the RTO’s risk modeling methodology during a meeting of the Critical Issue Fast Path (CIFP) process July 17.

The meeting included a second proposal from Daymark Energy Advisors and the East Kentucky Power Cooperative (EKPC) that would modify PJM’s proposal and a presentation from American Municipal Power (AMP) that suggested several changes to the Independent Market Monitor’s proposal.

Daymark CEO Marc Montalvo described its second joint package with EKPC as a trimmed-down version of the PJM proposal, with changes including retaining the annual Base Residual Auction structure instead of moving to a seasonal auction and preserving the fixed resource requirement structure. (See “Daymark and EKPC Propose Base and Emergency Capacity,” PJM Completes CIFP Presentation; Stakeholders Present Alternatives.)

While the proposal retains PJM’s proposed marginal effective load-carrying capability (ELCC) accreditation model, Montalvo said it’s not the preferred long-term solution for a forward market structure as more renewables come online.

The proposal would use an hourly reimbursement model that would pay resources for the capacity they provide in each hour of a delivery year, meaning they would offer their committed capacity into the real-time and day-ahead markets and follow dispatch. Generators would not be paid for their capacity for hours in which they do not do so.

Natural gas resources that have an offer in the markets but are called on too late to nominate for fuel according to the gas pipeline procurement timelines would retain their capacity commitment. Montalvo said the interaction between the gas and electric timelines are an operational issue and ensuring that dispatch doesn’t conflict would be PJM’s responsibility.

Resources would be able to engage in bilateral contracts to meet their capacity obligations and would be expected to do so when prolonged outages are anticipated.

Montalvo said the objective in drafting the proposal was to create a penalty framework that incentivizes performance without jeopardizing the viability of long-term resources when they’re assessed.

AMP Suggests Changes to Monitor Package

AMP’s Lynn Horning gave an overview of several changes the organization believes would build on the sustainable capacity market design proposed by the Monitor.

AMP has its own CIFP proposal that would create subannual accreditation and replace the Capacity Performance penalty construct with a reward and penalty system built around testing performance and providing “pay as you go” capacity payments. (See “AMP Seeks Subannual Accreditation,” PJM Stakeholders Refine CIFP Capacity Market Proposals.)

Horning said the Monitor’s proposal has the benefit of focusing on defining demand for each hour and matching that with adequate load. It also includes locational elements and simplifies the auction clearing process. She said the Monitor’s proposal to create a new accreditation model, the modified equivalent availability factor, also is preferable to PJM’s marginal ELCC approach because it avoids the latter’s interactive effects and improving the focus on real-time operations.

The changes to the Monitor’s proposal made by AMP include allowing natural gas generators to submit start, notification and minimum run time parameters on a shorter time frame based on pipeline conditions and to permit them to reflect a wider breadth of costs related to pipeline service in capacity or energy offers.

The AMP proposal also calls for retaining energy efficiency resources in the capacity market — the Monitor’s package would remove them — and differentiating the availability of demand- and supply-side demand response resources.

Planned capacity resources would be required to notify PJM if they plan to submit an offer in the BRA prior to the posting of the planning parameters for that delivery year, which has been a topic of stakeholder discussion since the absence of planned resources in the 2024/25 BRA was attributed to PJM delaying the release of auction results last year. Resources that do not indicate that they plan to participate in the auction would be permitted to offer only energy bids. (See FERC OKs PJM Proposal to Revise Capacity Auction Rules.)

AMP also called for a second CIFP phase to discuss holding BRAs closer to their associated delivery year, creating a subannual procurement system with time-of-day procurement assessments and exploring additional ways of creating comparability between the capacity market and FRR systems.

PJM Updates Risk Analysis Figures

PJM also presented updated reliability risk modeling figures, aiming to capture a broader range of threats to reliability and evaluate the differences between how an expected unserved energy (EUE) method of deriving the requirement would capture risk and the status quo loss-of-load expectation. (See PJM Continues CIFP Discussion of Seasonal Capacity Market Proposal.)

The new data pare back the preliminary findings PJM presented at the May 30 CIFP meeting, which showed a sharp shift in risk toward winter, particularly under the EUE model. While the new data still have risk concentrated in the winter, the season now makes up only about 64% of the risk under the baseline model, rather than the 96% in the preliminary data.

The presentation also included three additional models that include a longer historical weather lookback — going back 50 years instead of 30 — and two adding in climate change adjustments as well. The longer historical lookback increases the winter risk to 71%, but the two climate change variants both swing risk back to being predominantly in the summer.

Method A, which results in the higher summer risk, estimates the trend that climate change is having on seasonal minimum, mean and maximum temperatures to create adjustments that are applied to historical temperatures to consider how past weather would manifest under future climate conditions. Method B follows the same system, but only for mean temperatures.