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November 5, 2024

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DTE, Activists Announce Agreement to Exit Coal by 2032

DTE Energy announced an agreement with Michigan officials and environmental and clean energy groups Wednesday to accelerate its emission-reduction efforts, add more renewable power and phase out coal use by 2032.

Under the agreement on DTE’s 20-year integrated resource plan, the utility will cut its power plant emissions by 85% in the next nine years, with the utility committing to net-zero emissions by 2050.

The proposed agreement (U-21193) will have to be approved by Michigan’s Public Service Commission, which is expected to consider it at its next meeting July 26. The PSC staff was among the parties to the settlement, along with Michigan Attorney General Dana Nessel and 21 environmental and clean energy groups and labor unions.

Coal Retirements

The deal will end the use of coal at the Monroe plant, the nation’s fourth-largest, by 2032, three years earlier than DTE had previously announced. In addition, DTE will convert its only other coal-fired generator, the Belle River plant in St. Clair County, to natural gas.

DTE will also close the gas peaker unit (11 MW) at the shuttered River Rouge coal plant and diesel peaker (5 MW) at the retired St. Clair coal plant in 2024.

The company agreed to begin conversion of Belle River within three years and to seek federal funding for the work under the Inflation Reduction Act.

Monroe Units 3 and 4 will be retired by the end of 2028 and Units 1 and 2 by the end of 2032, assuming no regulatory orders to keep them open or designation by MISO as system support resources. DTE said it will propose how to replace the power from the 3,400-MW Monroe plant in its next IRP, due in 2026.

The company pledged to offer retraining for employees impacted by the coal plant retirements and offer “economic development opportunities” for host communities.

Coal represented 77% of the company’s generation in 2005. For 2022, the company’s generation mix was 54% coal, 18% nuclear, 14% natural gas and 13% renewables.

15,000 MW of Renewables

The agreement was developed over two years of discussions. (See DTE CEO Hints at Accelerating Coal Plant Closures.)

There was some grumbling that the agreement was not as aggressive as Consumers Energy’s plan to end the use of coal by 2025. But overall, the advocacy groups were satisfied with the agreement.

DTE said the IRP also calls for developing more than 15,000 MW of renewable generation by 2042 and more than doubling its current storage capacity with the addition of 780 MW by 2030 and more than 1,800 MW by 2042. The storage plan will include 220 MW at the Trenton Channel Power Plant, a former coal plant.

Also, the company also will seek 150 MW of new demand response through competitive bidding in time for MISO’s 2027/28 planning year.

The IRP indicated no need for generation capacity in the next five years.

Nessel touted several other parts of the agreement:

    • $100 million in customer savings from securitizing at a lower rate more than $1 billion in early retired coal plant assets and reducing the return on equity on currently operating coal plants;
    • DTE’s donation of $8 million for energy efficiency and renewable projects for low-income customers and $30 million to reduce arrearages;
    • annual public disclosures of all contributions made by DTE and its regulated utilities that total $5,000 or more, including donations to tax-exempt 501(c)(3) and 501(c)(4) organizations;
    • increasing DTE’s cap on distributed generation from 1% to 6%; and
    • DTE’s allocation of at least $43.8 million to income-qualified electric energy waste reduction programs in 2024 and $53.8 million in 2025.

Activist groups said the agreement will reduce the health risks lower-income populations face from the power plants.

“This legal settlement commits DTE to an expeditious transition away from burning coal that is compelled by economics, public health and climate science,” said Earthjustice attorney Shannon Fisk. “With the Monroe coal plant — the third-largest climate polluter in the country — partially retiring in 2028 and fully retiring by 2032 (or possibly earlier), people in southeast Michigan will soon begin to breathe easier. Today’s settlement will accelerate the buildout of clean solar and wind power in Michigan, as well as battery storage, and it funds energy-efficiency programs.”

DTE CEO Jerry Norcia called the agreement “an investment in Michigan’s future.”

“We are grateful that 21 organizations from across Michigan have joined us in bringing our proposal one step closer to reality. This partnership and dedication have helped us build the best plan possible for our customers,” he said.

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MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours

CARMEL, Ind. — MISO is holding to its plan to enact a widescale marginal capacity accreditation while announcing this week that it will swap risky hours for peak load to calculate its reserve margin requirements.

Officials at a July 11-12 Resource Adequacy Subcommittee (RASC) meeting said as part of MISO’s move to a probabilistic, direct loss-of-load accreditation for most of its resources, it will identify periods that have the highest potential for reliability risks in its loss-of-load modeling and set requirements from them. That process is set to replace MISO’s current practice of margin requirements established on peak load.

MISO also proposed a three-year transition to the direct loss-of-load accreditation, which will be based on generator performance during predefined tight operating conditions. The grid operator hopes to file the changeover with FERC in October or November. (See MISO Accreditation Impasse Persists at Workshop; MISO Stakeholders Debate Capacity Accreditation, RA.)

MISO’s Davey Lopez said staff will reach out to market participants in the coming months with accreditation results under a direct loss-of-load approach. He said MISO is working with Astrapé Consulting to estimate accreditation trends into the future under a transformed fleet. MISO plans to use results from its annual Regional Resource Assessment to publish forward-looking accreditation and planning reserve margin requirement estimates. (See MISO: 200 GW in New Capacity Necessary by 2041.)

“We will only make a filing after you all have seen both the…accreditation and the notional trend of what accreditation will look like under a different resource mix,” Executive Director of Market and Grid Strategy Zak Joundi pledged. He said MISO will build in its filing how it will share accreditation data from “a future-looking standpoint.”

Joundi said it makes sense for MISO to leverage the annually updated Regional Resource Assessment to predict the fleet mix MISO will be accrediting.

Joundi also said though MISO’s reserve margin calculations will be adjusted to focus on risky hours, they still will incorporate seasonal peak loads and still will solve to meet them.

“It’s just signaling that’s not where we’re seeing risk happening,” Joundi explained of MISO’s new calculation route.

So far, the accreditation change will not apply to load-modifying resources. Lopez said MISO plans to address LMR accreditation later.

MISO officials are wedded to the direct loss-of-load accreditation as stakeholders continue to have qualms with the lowered capacity credits for most resources and eventual near-zero capacity credits for solar generation that the design is likely to produce within a decade.

Stakeholders’ motion in spring to oppose a marginal approach to capacity accreditation passed with 31 members in favor, six voting against and eight abstaining from the email vote.

MISO’s Dustin Grethen said he “invited people to think of” MISO’s accreditation philosophy as what capacity is actually earned, versus the cruder, nameplate capacity-minus-forced outages MISO previously employed for its thermal resources.

During the May Resource Adequacy Subcommittee meeting, Joundi said MISO and stakeholders already have been debating accreditation design elements for the better part of two years.

“The way we landed on the proposal on the table was not by luck,” Joundi said, adding that MISO staff underwent months of analysis on the most beneficial accreditation design for the system. “We believe the current proposal…meets where we need to be to be ready for the future and is the most appropriate.”

Stakeholders pushed back on the timeline, saying that though discussions were held on accreditation concepts, MISO only settled on a draft design since early 2023.

Lopez said it just makes sense that accreditation should be directly derived from loss-of-load expectations.

“They’re in the same currency,” he told stakeholders at the May RASC.

MISO Independent Market Monitor David Patton said that MISO must continue its effort to assign realistic capacity accreditation to all units, despite stakeholder protest. (See MISO Accreditation Impasse Persists at Workshop.)

“There’s a lot of folks behind me that aren’t going to like an efficient accreditation regime because these resources are expensive to build, but if we’re not honest about that, we’re going to accredit resources that have no hope of meeting the planning margin,” Patton said during the spring MISO Board Week.

Patton said without an honest accreditation method, MISO runs the risk of not having “the resource base that we need to keep the lights on.”

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MISO Members Suggest Improvements After 1st Seasonal Capacity Auction

CARMEL, Ind. — In the wake of MISO’s first seasonal capacity auction, members have asked MISO to improve its generator outage rules, its preliminary data sharing and the registry tool used to track capacity.

MISO surveyed its members on what improvements it should prioritize before the 2024/25 Planning Resource Auction (PRA) in the spring. This week, the RTO said members had concerns over its 31-day outage threshold and said abiding by the rule is time-consuming and could produce a less reliable fleet. They also asked MISO to share preliminary PRA data sooner and better explain how it derives estimated capacity values. Finally, members singled out MISO’s nonpublic load forecast and resource registry for improvements, saying the current tool lacks a consistent naming convention, requires duplicative data entry of market participants and should have a dispute option for load and capacity values.

Stakeholders a year ago first requested better and more timely preliminary data ahead of the auction after the 2022/23 capacity auction laid bare a 1.2-GW shortfall across the Midwest region. (See “Stakeholders Ask for Data Improvements,” MISO Promises Stakeholder Discussions on Capacity Auction Reform.)

At a July 11 Resource Adequacy Subcommittee, Independent Market Monitor David Patton said he shared members’ concerns over the new 31-day limit on nonexempt unit outages in a season.

“One of our conclusions from administering mitigation and monitoring the market is it’s not an optimal structure,” Patton said. “When you have the 31-day grace period, it causes generators to move outages into two seasons.”

Patton said it’s “not great” to have generators avoiding penalties by nudging outage schedules so they straddle both spring and summer, where generator availability becomes critical. He underlined the drawback to the new outage rules in last month’s State of the Market report. (See MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

“We’d like outages to be taken based on when they’re the least costly to take and not be influenced by an arbitrary penalty structure,” he said.

Patton suggested MISO adopt more gradual penalties that account for the number of days a generator is unavailable so generator operators aren’t abruptly facing penalties at the 31-day mark that must be reflected in capacity offers.

Consumers Energy’s Erika Ward said she worried that generators will begin delaying maintenance to avoid outage penalties, risking catastrophic failures. But Patton said even without a capacity market, generator owners must balance missing out on payments versus undergoing necessary maintenance.

Executive Director of Market and Grid Strategy Zak Joundi said MISO doesn’t yet have a timeline on how it might adjust its outage limit.

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MISO FTR Underfunding Hits $60M in Spring, Improvements Coming in 2025

CARMEL, Ind. — MISO’s Independent Market Monitor this week reported that the RTO’s financial transmission rights market came up short by more than $60 million this spring.

At a July 13 Market Subcommittee meeting, IMM staffer Carrie Milton of Potomac Economics said the FTR spring underfunding can be chalked up to transmission outages that were shifted after the auctions and “topology” differences between MISO’s FTR market and its day-ahead market.

The IMM said it ultimately reported a transmission owner to FERC for failing to report planned transmission outages and acquiring undeserved FTRs.

MISO has become increasingly concerned over its congestion-hedging market’s underfunding in recent years. It has said there’s a growing discrepancy between awarded auction revenue rights (ARRs) and the footprint’s actual congestion patterns. As a result, load-serving entities hold a historically smaller share of FTRs, and the ARRs’ congestion value has fallen.

MISO has said it will adopt slow and measured modifications to its ARR and FTR market rather than enacting sweeping changes after a consulting firm found MISO’s market could use improvements to correct underfunding.

MISO favors a methodical approach where it makes one or two changes and then examines the impacts before revising further. The first change up for implementation is to adjust the rights allocation so it corresponds better to current network usage, rather than a more-than-10-year-old snapshot of the system. MISO doesn’t plan on introducing that change until 2025.

If enacted, the change would take care of London Economics International’s (LEI’s) most pressing recommendation that MISO’s market should be updated with new resource entries and retirements to better reflect transmission use. (See Financial Firm Finds MISO FTR Market Needs Work.)

MISO’s Jack Dannis has said MISO isn’t looking to rebuild its ARR/FTR process. He said a complete overhaul and redesign would be labor-intensive and unnecessary.

“We don’t feel that would align with LEI’s findings. They saw a lot of good in the market,” Dannis said during the April meetup of the Market Subcommittee.

MISO reported its year-end excess congestion fund disbursement was about $350 million in 2022, much larger than in previous years. The congestion fund is distributed back to transmission customers on a pro rata share after the year’s FTRs are fully funded. MISO said the larger amount in 2022 was due to a lower FTR shortfall last year, an increase in day-ahead excess congestion after hourly funding and an increase in monthly FTR auction revenues.

MISO issues the financial instruments based on transmission capacity; they are used by load-serving entities and other market participants as financial hedges against congestion charges in the day-ahead market. MISO funds FTRs through day-ahead congestion costs; an ARR is the LSE’s entitlement to a share of revenue from FTR auctions because of its historical use and investment in the transmission system.

Load-serving entities buy FTRs as a congestion hedge on the transmission system from their resources to load. They differ from the financial traders in the market, who seek profits.

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DOE Awards $90 Million for More Efficient, Resilient Building Codes

Only about one in three state and local jurisdictions across the U.S. have adopted the most recent ― meaning the most energy-efficient and resilient ― building performance standards, and the Department of Energy on Wednesday announced $90 million in grants to help some of the other two-thirds get up to code.

Funded by the Infrastructure Investment and Jobs Act, the awards are going to 27 projects across 26 states and Washington, D.C., “to ensure buildings meet the latest standards for energy efficiency,” according to the DOE announcement. “Modernizing energy codes is one of the most cost-effective ways to improve energy efficiency in homes and businesses and make communities more resilient to extreme weather events.”

The list of awardees range from organizations such as the American Council for an Energy-Efficient Economy (ACEEE), which will establish a National Building Codes Collaborative, to the University of Cincinnati, which will study cost-effective ways for Ohio’s large cities to design and implement efficient, equitable building codes.

Grants range from $1 million to ACEEE’s $9.6 million.

“Cutting emissions from buildings across America and ensuring they’re more energy efficient are critical components of President Biden’s plan to tackle the climate crisis and create cleaner, healthier communities,” Energy Secretary Jennifer Granholm said in the announcement.

The announcement comes as temperatures climbed into triple digits — and excessive heat warnings and watches were issued — in the Southwest, Texas and southern Florida.

According to DOE, the U.S. has about 130 million commercial and residential buildings that are responsible for 35% of the country’s total greenhouse gas emissions. The most recent building code — the 2021 International Energy Conservation Code (IECC) issued by the International Code Council — has been adopted by only five states, according to DOE’s Building Energy Codes Program: Vermont, Connecticut, New Jersey, California and Washington.

Half of the states are using codes that are more than 10 years old. The code is updated every three years, and work is underway on the version to be released in 2024.

An additional eight states are home-rule states, which have no statewide building codes; local jurisdictions determine what building codes are adopted. For example, in Colorado, Denver has adopted a “green” code that encourages energy-efficient, emission-cutting design and construction.

The impact of adopting more efficient codes can be significant. Homes built to current code are 40% more efficient than those built 15 years ago, DOE said. The department estimates that modernizing building codes across the country could save consumers $138 billion through 2040 while cutting GHG emissions by 900 million metric tons.

National Building Code Collaborative

Based on the list of awardees, the DOE funding is targeting regional and collaborative efforts with the potential to create replicable models that can be used in other jurisdictions.

ACEEE is working with the National Association of State Energy Officials and the Urban Sustainability Directors Network to establish the National Building Codes Collaborative, said Amber Wood, director of building programs.

“The big overarching view is that we intend the collaborative to basically … have webinars and technical assistance sessions where anyone and everyone is welcome,” Wood said in an interview with NetZero Insider. The goal, she said, is “advancing building energy codes … so we’re talking about new buildings as well as increasingly talking about building performance standards for existing buildings.”

In addition, ACEEE will be working directly with four states where the organization will provide staff “to help advance their energy code and build capacity,” she said. The states include home-rule state Colorado; Louisiana and Michigan, both of which have not updated their codes since the 2009 version of the IECC; and New Jersey, which has adopted the 2021 IECC but is getting ready for the 2024 update.

Wood says the roadblocks to building code updates may vary across states. “It depends on … how the legislation is set up. Is there opportunity to advance it?” she asked. “There’s obviously a lot of impact if you can get a whole state to go to a higher energy code, but there’s also a question of, can you get the localities to do that as well? How do you support both state and local jurisdictions to do this?”

Wood also pointed to the other benefits of updated building codes, such as public health, comfort and resilience. “Energy efficiency and decarbonization are extremely important, [but] that doesn’t resonate with everybody,” she said. “So how can we talk about some of the real benefits that maybe can hit a broader audience?”

Energy-efficiency ‘Circuit Riders’

On a smaller scale, ClearlyEnergy, a software firm in Severna Park, Md., will receive $2.9 million to create “regional cohorts” that will work together to adopt building performance standards and energy-efficiency programs, with a special focus on small, rural and environmental justice communities.

The company has developed software that allows small towns or other jurisdictions to digitize compliance with building performance standards, making it easier for building owners to provide their data, said Carolyn Sarno Goldthwaite, vice president of customer engagement.

The company is helping D.C. implement its building performance standards and is also partnering with agencies in Pennsylvania and West Virginia, which will be setting up their own regional cohorts, she said.

The cohorts “will help small, rural, underserved communities set up and establish both benchmarking [and] building performance standards,” Goldthwaite said. “Oftentimes, jurisdictions don’t have enough staffing to manage these policies, so they don’t adopt them, and so our cohort approach is that they can leverage one another, and they can set up a regional framework [that] all jurisdictions could use.”

ClearlyEnergy will also be providing on-the-ground technical support in the form of building performance standards “circuit riders”: traveling staff who will “help building owners understand how they can reduce their energy consumption in their buildings,” Goldthwaite said.

“We don’t want them just to adopt a policy and have this tool. We want to make sure we’re supporting them to actually do the energy reductions within those buildings.”

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Federal Plans to Electrify Highway Corridors Advancing

A five-year, $5 billion effort to establish a nationwide network of public EV chargers along designated highway corridors is pushing ahead as planned, according to a report on the first year of the National Electric Vehicle Infrastructure (NEVI) program.

The effort, launched in February 2022, required states to file their EV charging plans by Aug. 1, 2022, a relatively quick turnaround.

The Joint Office of Energy and Transportation received all 52 state plans by the deadline and the Federal Highway Administration approved them within two months, “unlocking $1.5 billion in funding for states to begin building charging stations through the NEVI formula program,” the report said. (See States File Plans on Deadline for EV Charging Funds.)

(The Joint Office was created through the Bipartisan Infrastructure Law in 2021 to foster collaboration between the Department of Energy and Department of Transportation.)

The largest recipients of the $1.5 billion funding in 2022/23 were Texas, which received $147 million, and California, which was awarded $138.5 million.

The Joint Office’s analysis showed that “most states already have adequate funding to become ‘fully built out,’” with EV chargers every 50 miles along 75,000 miles of designated alternative fuel corridors. Those corridors include 92% of the nation’s 48,000 miles of interstate highways and a third of the 230,000-mile National Highway System.

“Once fully built out, up to $3.5 billion in funding could be available for EV charging beyond designated corridors,” the report said.

As of March, 679 charging stations in the corridors met NEVI requirements for distance between stations and had sufficient charging ports and capacity, the report said.

The multi-year effort still has room for improvement in the areas of procurement, station siting, cybersecurity, program evaluation and community engagement, it said.

“These topics will be emphasized in technical assistance provided by the Joint Office,” it said.

Among the issues still to be worked out is the type of chargers required at NEVI sites.

There has been increasing concern that the North American Charging Standard (NACS) connectors used by Tesla are quickly becoming the national standard while federal NEVI guidance requires charging stations to be equipped with the rival combined charging system (CCS) connectors. (See EV Charging Efforts Ramp up on West Coast.)

In the past two months, automakers including Ford, General Motors, Mercedes, Rivian and Volvo have announced they plan to adopt Tesla’s NACS connector as Tesla begins opening its Supercharger network to non-Tesla vehicles.

Another question is how the U.S. will install the vast number of chargers needed to support a switch to electric vehicles.

While NEVI’s $5 billion is meant to jump-start the effort, a study by the National Renewable Energy Laboratory estimated that the U.S. needs 1.2 million public charging stations to support 33 million light-duty vehicles by 2030, the report noted. That will require 28 million charging ports, both public and private, and cumulative investments of $53 billion to $127 billion, it said.

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NERC FAC Approves Transfer Study Funding

In a special meeting Wednesday, NERC’s Finance and Audit Committee agreed to a preliminary plan that will allow the organization to fund a two-year study on interregional power transfer capability ordered by Congress last month.

Congress mandated that the ERO perform the study as part of the Fiscal Responsibility Act. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.) The FRA requires that NERC, in consultation with the regional entities, deliver to FERC by December 2024 a study that examines:

    • The current total transfer capability between each pair of neighboring transmission planning regions;
    • Recommendations of “prudent additions” to total transfer capability that could strengthen grid reliability; and
    • Recommendations to meet and maintain total transfer capability together with such recommended additions.

The FAC’s approval of the plan means the ERO will not have to order a special assessment to pay for the part of the study’s costs that will be incurred this year if FERC agrees to the proposal, which is required because it calls for drawing from NERC’s financial reserves. Staff said they intend to submit the plan to FERC by the end of this week.

Speakers at Wednesday’s meeting acknowledged that Congress’ order would force NERC to defer some projects and planned hiring for 2023 and 2024. At the same time, NERC CEO Jim Robb expressed pride that the ERO had been chosen to conduct a study he called “unprecedented” due to its scope and called NERC “the ideal organization to be conducting this assessment.”

“I think the reason this came to NERC is that we’ve had a long history of highlighting the need for more infrastructure, including transmission and … natural gas pipelines, in all of our reliability assessments, and our independent voice for reliability … is very, very important here,” Robb said. “This challenge is only going to grow if we don’t address it in a timely, well-thought-out manner, and in conjunction with the work that we’ve been asked to do on extreme weather and environmental conditions. It all needs to be pulled together.”

NERC staff presented a phased approach to the interregional transfer study at the FAC meeting. Currently the ERO is in “Phase 0,” or preparation for the study; if FERC approves its spending plan, then Phase 1 can begin by Aug. 15. | NERC

The project is in what NERC staff called “Phase 0,” for defining the study scope, assumptions and scenarios. Phase 1 — when the ERO and its partners will identify areas with deficient and surplus generation, perform the transfer capability analysis and identify thermal, voltage and stability limits — could begin as early as next month if FERC grants approval. NERC hopes to produce its draft recommendations by next August.

According to the resource plan presented Wednesday, NERC will need to hire four technical staff members — a project manager, an engineering manager and two engineers — along with a communications professional. Also, outside consultants will be required to provide “executive leadership” and public affairs support, along with helping perform the study itself.

Paying for the study will require revising NERC’s 2024 business plan and budget, a draft of which the ERO published before Congress passed the FRA. (See Personnel, Meeting Costs Drive 2024 ERO Budget Hikes.) CFO Andy Sharp told attendees the study’s effect on the 2024 budget and assessment still is being evaluated but that the FAC should be ready to provide an updated budget to the Board of Trustees at its meeting in Ottawa next month.

To cover the costs of the study this year, NERC has reprioritized its 2023 work plan to free up its cash flow. This includes deferring several projects planned for this year, including a special assessment on new and evolving electric market practices and studies on geomagnetic disturbances, cybersecurity risks and environmental impacts. NERC also will defer until 2024 plans to fill three open positions in bulk power system awareness, engineering and security, and standards.

However, Mark Lauby, NERC’s senior vice president and chief engineer, assured listeners the organization would work to minimize the effects of these changes by incorporating some of the work of the deferred projects into other work areas. For example, Lauby said some of the planned assessment on market practices can be captured in NERC’s Long-Term Reliability Assessment this year, while other aspects of the assessment can be incorporated into the transfer study itself.

After deferring these costs, NERC estimates it will need an additional $700,000 to pay the estimated study costs this year. Sharp said the organization intends to draw the money from its Assessment Stabilization Reserve (ASR), which stood at $3.3 million at the end of 2022. Funding the study from the reserve, coupled with the deferred work, means NERC will not need to call for a special assessment in 2023.

The proposal drew unanimous approval from FAC members, with Trustee Bob Clarke calling the use of the ASR “a very appropriate [and] creative way to … use the funds that we have available” to minimize the impact on registered entities this year.

Trustee Sue Kelly concurred with Clarke, adding that using the ASR was especially appropriate because the reserve is funded by penalties on U.S. entities. Therefore, tapping these funds would “mute the impact on our Canadian brothers and sisters,” which seemed fair because the study was ordered by the U.S. government without Canada’s involvement.

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AEU Webinar Examines Ways to Get to ‘YIMBY’ for Transmission

Transmission projects often run into local opposition, but that can be turned into support if communities are approached early in the process and even invited to earn money off lines that go through them, according to speakers on an Advanced Energy United webinar Wednesday.

One example of a transmission project working with a local community was Southern California Edison’s West of Devers project that sought to upgrade a 50-year-old transmission line to bring in more renewable power to SCE’s customers from the east, said former FERC Commissioner Suedeen Kelly, now a partner at Jenner & Block.

The old transmission line went through tribal land of the Morongo Band of Mission Indians, who live near Palm Springs. The old line had a right of way that expired early in the last decade, which the utility needed to expand in terms of its geographic footprint, as well to upgrade the line from 230 kV to 345 kV.

“Now, the interesting thing is that there is no power of eminent domain on tribal lands,” Kelly said. “This was a situation that started with some tension. The tribe had only been paid a minimal amount of money — less than $100/year for this old right of way. And they didn’t feel at all warm and fuzzy about extending the right of way, either in time or in width.”

SCE reached out to tribal leadership to come to a mutually beneficial agreement, which wound up with the tribe becoming its partner in the development, investing $400 million for half of the project and earning returns on it through a new company called Morongo Transmission.

“The benefits were extraordinary to this joint venture,” Kelly said. “If Morongo had not agreed to the right of way, it would have meant rerouting the transmission line around the reservation at a cost of over $500 million. And it would have taken eight more years to get this transmission line between California and Arizona into place.”

The deal helped the line move forward, benefiting SCE’s customers and helping to implement California’s policy of growing renewable energy, while turning what had been a combative relationship into a collaborative partnership, she added.

FERC approved Morongo Transmission to collect annual revenue requirements for 30 years to recoup its investment, and those profits will go into tribal coffers to benefit the community, said Kelly. The deal benefited SCE’s other ratepayers because it avoided the costly upgrades and delays of going around their land.

The SCE-Morongo collaboration was based on a model pioneered by Citizens Energy, which was founded by Joseph P. Kennedy II in 1979. The company initially worked on similar deals in the oil industry, which helped low-income customers in New England get cheaper heating fuel. But the firm also has worked in the electric industry for decades and is working on transmission projects in California and the Northeast, said its managing director, Joseph P. Kennedy III. (The father and son are both former members of Congress, and are the son and grandson, respectively, of Robert F. Kennedy.)

“The company was founded over 40 years ago, by my dad, as an innovative nonprofit to help low-income families meet their basic needs,” Kennedy III said. “It is an interesting structure. It’s a nonprofit parent that sits on top of a bunch of different for-profit entities. So, we run it like a proper business: The revenues flow up to a nonprofit parent, and we give a large portion of our revenues away every year [to] communities that we serve to try to meet their needs.”

Citizens’ transmission model carves out part of a utility’s, or merchant developer’s, transmission investment to use for nonprofits that benefit communities impacted by the project. The firm will invest 10 to 20% of a project and use the rate-of-return to cover its costs and turn the rest of the returns over to local uses. The first project for which Citizens used that model was San Diego Gas & Electric’s Sunrise Powerlink, which brought renewable energy from the Imperial Valley to the utility’s territory.

“We now use the profits off of that line, our portion of the profits, to help finance the largest low-income community solar program in the nation,” Kennedy III said, “where 12,000 low-income households in the Imperial Valley get discount solar electricity every year for the next 20-plus years.”

The model holds promise to build the transmission needed to integrate the clean energy while giving local communities that host the infrastructure some tangible benefits, he said.

“It also sets you up not just for the engagement in this project, but it builds those relationships to talk about the next one, and to talk about what the needs of the community are,” Kennedy III said. “And to see, how in fact, we can help leverage this environmental and economic transformation that needs to happen from a national level and a global level to local benefit.”

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Discussion Continues on ISO-NE Capacity Market Changes

New England stakeholders continued discussion on potential changes to ISO-NE’s forward capacity market (FCM), debating the merits of moving to a prompt and seasonal capacity market at the NEPOOL Markets Committee (MC) on Monday.

ISO-NE declined to endorse any specific market changes, but solicited feedback and furthered the discussion on market alternatives initiated at the June Participants Committee meeting (See ISO-NE Considers Major Capacity Market Changes.) The RTO is facing a deadline to figure out how to proceed for the 2028/29 Capacity Commitment Period, the auction for which is scheduled for February 2025.

“By September 2023, ahead of the pre-auction process for FCA [Forward Capacity Auction] 19, the ISO must decide on the timing and scope for CCP19,” Tongxin Zheng, ISO-NE director of advanced technology solutions, told the MC.

For FCA 19, the RTO laid out the options of proceeding with the auction business-as-usual, delaying the auction until 2026 to incorporate the ongoing Resource Capacity Accreditation (RCA) project or delaying the auction until early 2028 while moving to a prompt and seasonal auction.

Looking at the long-term outlook for the region’s capacity market, ISO-NE presented some potential pros and cons of adopting prompt and seasonal market changes. For a prompt market, ISO-NE said the benefits would include improving the accuracy of forecasts, requiring projects to be operational to enter the auction and eliminating several “challenging elements of auction administration,” such as non-commercial financial assurance and annual reconfiguration auctions.

“A prompt construct can improve the accuracy by which we estimate resource adequacy (demand) and resource accreditation (supply) relative to the current forward construct,” ISO-NE said. “However, the potential improvements are a function of what ‘prompt’ means in practice.”

Meanwhile, ISO-NE said it anticipates some drawbacks inherent to moving to a prompt market. These include making auction results less important for the long-term entry and exit decisions of generators, increasing capacity price volatility and giving less time for the RTO and market participants to react to the auction’s outcomes.

Pete Fuller of Autumn Lane Energy Consulting told RTO Insider that new changes must consider impacts on new resources, especially within the context of the clean energy transition.

“In the current debate about a prompt capacity market, we should think very carefully about whether a prompt market will support the level and kinds of new entry that will be needed for the decarbonization transition as state-backed contracting is phased out,” Fuller said, noting that the current FCM was designed to help provide new entrants with some degree of price certainty several years out.

“While current practice in the region relies much more heavily on state-backed contracts for entry decisions (particularly for offshore wind projects) than on the markets, that may not always be the case, as suggested by Massachusetts’ recent work to explore the Forward Clean Energy Market concept,” Fuller added (See New England Stakeholders Discuss Clean Energy Market Mechanisms.)

Some stakeholders, however, view the lack of a years-in-advance capacity commitment requirement as a benefit for developing new projects.

“The uncertain development timeframes for a growing share of new resources, including offshore wind, causes the FCM to create inefficient financial risk for new resources that may become an economic barrier for new investment,” said Pallas LeeVanSchaick of Potomac Economics.

LeeVanSchaick also said the current FCM structure can push some existing units to retire earlier than they should.

For older, existing units, “unexpected issues such as significant equipment failure can compel them to buy back their capacity supply obligation at great cost and this risk may cause some resources to retire prematurely,” LeeVanSchaick said. “A prompt market facilitates more efficient retirement decisions because the uncertainty regarding the condition and availability of older units is much lower at the time of the auction.”

Under the current system, many older resources will simply run until something breaks, instead of scheduling the retirement in an orderly fashion, said Brett Kruse of Calpine.

“Some owners will operate the generator only during very high-priced periods until the unit or a major component has a major maintenance issue, and then they’ll decide that it does not make financial sense to allocate sufficient capital to repair the plant,” Kruse said. “They’ll just retire it, and that’s likely to be the way that most of the older plants eventually exit the market.”

ISO-NE has put forward a prompt market and a seasonal market as complimentary, but has not ruled out any options, including implementing just one of the two major changes.

Contemplating the benefits of a seasonal market, ISO-NE said a seasonal market could help the RTO do a better job modeling resource constraints and would allow suppliers to make offers reflecting their differing seasonal capabilities.

“A seasonal construct would allow for a more precise delineation of resource adequacy and resource accreditation values within a given annual delivery period,” ISO-NE said.

The RTO also asked stakeholders for input on whether it would be best to run seasonal auctions sequentially or concurrently. Kruse said that holding an integrated annual seasonal auction would help generators ensure adequate annual revenue.

“It’s important that the seasons, whether it is two or four, together provide sufficient annual capacity revenue to generators regardless of their seasonal value,” Kruse said. “Plant staffs, maintenance expenses and so forth are annual costs, so the totality of the seasons need to total up much like today’s annual market does, and having an integrated, annual view once a year for all seasons makes sense.”

DASI approval

The MC also recommended the approval of ISO-NE’s Day-Ahead Ancillary Services Initiative, which is intended to fill any energy gaps between the supply procured in ISO-NE’s day-ahead market and the RTO’s forecast real-time load (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.) The initiative will go to the NEPOOL Participants Committee for a vote on Aug. 3.

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NYISO Discovers Market Problem, Opens Confidential Investigation

NYISO has identified a software issue that potentially constitutes a market problem and will investigate the impact, according to an email the ISO sent to market participants Tuesday night.

In the email, which was obtained by RTO Insider, NYISO said it “is conducting a confidential investigation into the issue” and that it “will inform market participants as soon as practicable after resolution of the underlying issue.”

Shaun Johnson, NYISO director of market mitigation and analysis, addressed stakeholder questions about the notice during a Wednesday meeting of the ISO’s Business Issues Committee.

Johnson said the ISO will label the investigation as “confidential” but does not expect it to be a “long-term” one.

The “expectation is that this issue will be addressed soon, and we will provide more information to the marketplace as soon as possible,” he said. He referred anyone interested in learning more about the procedures for reporting market problems to Section 3.5.1 of NYISO’s market services tariff.

Johnson said he was reluctant to divulge too much information for fear of any parties “gaming or creating harmful outcomes to the NYISO markets,” but sought to answer questions from those curious about the nature, timing and impact of the problem.

In response to a question from Mark Younger, president of Hudson Energy Economics, Johnson said the problem was identified in NYISO’s day-ahead and real-time ancillary services markets.

Andrew Antinori, a director at the New York Power Authority, asked how NYISO determines when an issue is graduated to a potential market problem.

“There’s no bright line or financial threshold, but in order to move from a potential market problem to a market problem, there needs to be a significant impact to market outcomes,” Johnson said.

“We are still in the stages of identifying the exact issue,” he added, “but at this point, it is a potential market problem, and we do not have our arms around the size, scope and impact at this point.”

Bruce Bleiweis, director of market affairs at DC Energy, asked how long the problem has been potentially impacting NYISO markets, and whether it was a “one-day, one-week, one-month or three-year problem.”

Johnson was hesitant to give an exact timeframe but said “it’s certainly been longer than one week and has been a somewhat significant period of time but does not go back several years.” He added later that “as of this morning, the problem has not been resolved.”

Marc Montalvo, CEO of Daymark Energy Advisors, sought clarification on the nature and magnitude of the issue.

Johnson was careful in his response. “There is a definitive issue with NYISO software,” but staff are still unsure “about the extent that issue had on NYISO market systems or will have on those systems,” he said.

However, Johnson made clear that if NYISO finds the issue to be a legitimate problem, then subsequent impact analyses “will glean the extent of the problem and if this was just a defect with little to no impact.”

Antinori and Doreen Saia, an attorney with Greenberg Traurig, asked about NYISO’s interaction with FERC and what, if any, tariff filings may be necessary.

Johnson responded that no tariff waivers or filings are currently necessary but that NYISO staff have been in contact with the commission to keep it appraised of the problem and get its “thoughts and guidance.”

“At this point, we do not expect there to be any need for additional market rules changes or exigent filing with FERC, and the expectation is that this will be resolved with updates to software,” he added.

NYISO must return with an update and more information within 30 days of initial notice, and Johnson said staff plan to return to the Market Issues Working Group meeting either Aug. 3 or 9.

June Market Performance

Also during the BIC meeting, NYISO Senior Vice President Rana Mukerji presented June’s market performance, highlighting how lower fuel prices and cooler temperatures significantly reduced energy prices compared with last year. The month’s locational based marginal pricing was roughly 60% lower than in the same month a year ago.

Mukerji said “fuel prices are at historically low levels” and “natural gas prices are 79% down year-over-year.”

DER Manual Updates

Also, stakeholders unanimously approved multiple distributed energy resource manual updates presented during the BIC meeting.

These updated manuals include revisions that have been discussed over the past year and are part of NYISO’s ongoing work to comply with FERC Order 2222, which required operators to enable DER aggregation market participation and deployment.

The manuals are now moved to the July 20 Operating Committee for approval, and NYISO anticipates the revisions will become effective on the same date as the launch of other tariff and participation models.