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November 2, 2024

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Regulators Propose New Independent Western RTO

PORTLAND, Ore. — The competition for organized markets in the West grew Friday as the Bonneville Power Administration launched a process to choose between day-ahead markets proposed by CAISO and SPP and regulators from five Western states urged the establishment of a new, independent RTO covering the entire West.

“This group proposes the creation of an entity that could serve as a means for delivering a market that includes all states in the Western Interconnection, including California, with independent governance,” regulators from Arizona, California, New Mexico, Oregon and Washington wrote to the chairs of the Western Interstate Energy Board (WIEB) and the Committee on Regional Electric Power Cooperation (CREPC).

The entity “could provide a full range of regional transmission operator services, utilizing a contract for services” with CAISO including eventual “assumption” of CAISO’s proposed Extended Day Ahead Market (EDAM) and its real-time Western Energy Imbalance Market (WEIM).

The letter cited studies that have shown the greatest economic and environmental benefits for the West would come from a single Western RTO. A state-led market study in 2021 found that development of an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion a year in energy costs by 2030.

“We have identified a common commitment in seeking the benefits shown in multiple studies that demonstrate the most favorable electricity market for consumers is one that includes a West-wide market footprint,” the letter said. “Such a market would avoid the issue of ‘seams’ from separate markets across major portions in the West and result in optimized use of resources to meet loads across the entire interconnection.”

“In announcing our commitment, the group is inviting all Western states and associated stakeholders to join the effort and help shape the approach,” it said.

The planning process will begin this year, and implementation will start in early 2024 “with the formation of the independent entity, the seating of an initial founding board of directors, exploration of the relationship with CAISO for future services and the expectation of a small independent staff being put in place,” the letter said.

‘A Breakthrough’

The prospect of a single West-wide RTO has been growing less likely as CAISO and SPP compete for market share for their proposed day-ahead offerings, and SPP is making inroads on the development of a Western version of its Eastern RTO called RTO West. (See Western Day-Ahead Markets Debated at CREPC-WIRAB.)

At the same time, the latest legislative effort to allow CAISO to become a Western RTO appears to have stalled. Assembly Bill 538 was held by its author in committee in May because of staunch opposition from powerful labor unions in California.

The bill would let CAISO create a governing body free from oversight by California politicians. Currently, the state governor appoints members to the ISO’s Board of Governors, and the state Senate approves them. (See CAISO Regionalization Bill Put on Hold.)

In the past, lawmakers have refused to relinquish control of CAISO, and other Western states have said they will not join an RTO dominated by Californians.

The regulators’ proposal could offer a way out of the stalemate and an alternative to Western entities thinking of joining SPP’s RTO West. “The letter represents a breakthrough in efforts to advance the regions’ energy landscape and is key to creating a market that fosters collaboration, improved reliability and economic growth,” Advanced Energy United, a national clean-energy trade group, said in a statement. AEU is part of a coalition of business and environmental groups called “Lights on California” that advocates for creation of a Western RTO.

The Environmental Defense Fund also is a coalition member.

“The positive thing to me is that this is the loudest signal to date that the West is organizing, and that is extraordinarily exciting and encouraging,” said Michael Colvin, who leads EDF’s work on California energy policy. “It’s an alternative to the SPP front. Whether it goes this way or the CAISO way, it recognizes that the most affordable and reliable way to achieve our energy goals and to decarbonize is through collaboration.

“It is a signal to all the folks that are thinking of jumping ship to SPP that the West is here for you.

In a statement to RTO Insider, CAISO CEO Elliot Mainzer said, “We are pleased that utility regulators from around the West have come together to discuss how they can work more closely together to enhance reliability and benefit ratepayers throughout the region. … CAISO stands ready to support their efforts and work with a broad range of stakeholders to develop a long-term approach that meets the needs of California and the entire Western U.S.”

SPP Vice President of Markets Antoine Lucas struck at diplomatic note in his comments on the development, saying the RTO understands that Western regulators want to “explore every available option” in their efforts to ensure that regionalization occurs with the interests of ratepayers in mind.

“SPP is confident in its ability to provide an independently governed market designed such that it will help states ensure electric reliability, reach their renewable goals, and enable equitable trade across the Western Interconnection,” Lucas said. “We stand ready to prove the integrity and value of our proposed Markets+ service and to meet the needs of Western stakeholders.” 

BPA: Markets+ vs. EDAM

The commissioners’ letter came just hours after BPA kicked off a public process at its Portland headquarters to determine whether it will participate in a day-ahead market and, if so, which option to choose: SPP’s or CAISO’s.

BPA operates about 70% of the transmission in the Northwest and is the region’s largest electricity supplier.

Friday’s workshop was to be the first of five such meetings to be held every other month through the beginning of next year, with each followed by a public comment period. BPA plans to propose a “record of decision” on the issue shortly after SPP files its Markets+ tariff with FERC in February 2024. It expects to conclude with a final workshop to discuss its decision and address the last round of feedback.

“This is an open-ended process; BPA has not decided to join a day-ahead market,” Russ Mantifel, BPA’s director of market initiatives, told workshop participants Friday.

But multiple sources involved in Western regionalization efforts, who asked not to be quoted because they’re not authorized to speak for their organizations, told RTO Insider that BPA is leaning toward Markets+. They cite a number of factors that put BPA in the SPP camp, including more favorable treatment for hydroelectric generation in Markets+, a CAISO bias in favor of California load that restricts wheel-throughs in the ISO during critical periods and the unresolved issues around the lack of independent governance for CAISO.

Governance is an especially intractable issue for BPA, which, as a federal power marketing agency, cannot cede its authority to a state-run organization, prohibiting it from participating in a CAISO-run RTO that is not overseen by an independent board.

And while membership in a full RTO is not on the table, Mantifel pointed to the importance of joining a day-ahead market that eventually can integrate more functions — such as resource adequacy — as conditions evolve in the West.

“One of the things we think about [regarding] governance, market design, etc., is which options create the opportunity to create more verticality, potentially going to an RTO or adding these functions as part of it, and which ones have had that sort of limitation,” Mantifel said.

Alex Swerzbin, director of transmission and markets for PNGC Power, a Portland-based generation and transmission cooperative owned by 16 utilities in seven Western states, agreed on the need for “verticality.” He encouraged BPA to consider the “end state” of its decision, which is future participation in an RTO. Swerzbin said the WEIM can be viewed as “sunk cost to a degree” because real-time trading still constitutes a small percentage of the market.

“Once we move to a day-ahead market, that is a much larger footprint. It is much harder to transition from one day-ahead market to a separate [market] to get to an RTO/ISO,” Swerzbin said.

But Fred Heutte, a senior policy analyst with the Northwest Energy Coalition, urged BPA to put aside an “A-to-B” comparison between EDAM and Markets+ in favor of considering the “big-picture question” of whether to have one or two markets in the West.

“The issue is going to be delivered value,” Heutte said. “If we have two markets, the likelihood, at least initially, from what we can see, is to have a significant reduction in delivered value in terms of cost, in terms of reliability and in terms of longer-term issues” such as transmission planning and resource adequacy, “no matter how good each of the market offers may be.”

Heutte said “the really big picture” is the impact of two markets on the diversity inherent in the Western Interconnection.

“If you look forward with the changing resource mix, with changes in extreme weather conditions, the changes in demand profile, as we see more large loads and more decarbonization load coming on the system, the resource and the load diversity of the West is a really critical factor,” he said.

“The more diversity, the fewer seams you have, the more effective [a market is] going to be — I can’t disagree with that,” Mantifel said. “I think … the other reality is what it takes to get there, and sort of the sacrifices and compromises people are willing to make in order to achieve that, and whether that’s ultimately viable.”

BPA has scheduled its next day-ahead market workshop for Sept. 11-12.

BPA expects to conclude its process for deciding on a day-ahead market early next year. | Bonneville Power Administration

CAISO is expected to file tariff language with FERC on EDAM next month. It has been promoting the day-ahead market among potential participants as it faces stiff competition from SPP.

On Thursday, CAISO said it would co-host a market forum on EDAM with NV Energy, PacifiCorp and others in Las Vegas on Aug. 30.

“The forum, which aims to foster a dialogue on the evolution of the EDAM in the West, will bring together leadership from regional utilities to discuss and share their thoughts on the factors and processes in considering their participation, as well as utility regulators from across the West, who will share their perspective on the next step in market evolution and how they are actively engaging in its development,” CAISO said.

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OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028

MISO and the Organization of MISO States’ 10th annual resource adequacy survey warned that a more than 9-GW shortfall could loom by the decade’s end, though it painted an adequate supply picture for the coming year.

MISO and OMS found the footprint will have 1.5 GW of residual capacity beyond the summer planning reserve margin requirement in the 2024/25 planning year.

However, survey results in the four subsequent years are light on reassuring news.

The organizations said that without swift action, a 2.1-GW total shortage is possible the summer of the 2025/26 planning year, a 3.4-GW deficit by the 2026/27 planning year, a 4.8-GW gap in the 2027/28 planning year and a 9.5-GW shortfall by the 2028/29 planning year.

According to the survey, MISO Midwest’s potential capacity deficits start in the summer of the 2025/26 planning year, while MISO South shows a potential deficit brewing by winter 2027/28. MISO and OMS said so far, the seasons outside of summer show sufficient — yet declining — capacity.

MISO said about 90% of its generating fleet responded to this year’s survey.

This year, the survey was divided by season to reflect MISO’s new seasonal format and projected capacity values across four seasons for the next four years. Results were delayed by more than a month because of MISO’s monthlong auction delay on a FERC show-cause order.

MISO and OMS are betting that demand grows at a clip of 0.8 GW or 0.68% per year on average and the planning reserve margin requirements climb from 7.9% in the 2024/25 timeframe to 9.2% in 2028/29. MISO used its loss-of-load modeling to predict margin requirements.

The two also said the survey showed potential capacity additions of as much as 6.9 GW in the 2025/26 planning year, 13 GW in 2026/27, 17.1 GW in 2027/28 and 20.7 GW in 2028/29, which could offset the potential shortages. Historically, MISO grants grid access to about 2.5 GW per year on its system. As of last month, MISO’s generator interconnection contained 1,412 active projects totaling almost 241 GW.

“These results continue to illustrate the reliability risk we face and reinforce the need for dispatchable, long-duration resources to be maintained and brought online to manage the transition to weather-dependent, low-carbon resources,” MISO CEO John Bear said in a press release.

This survey’s potential deficits are marginally better than those from last year’s OMS-MISO survey, which projected the footprint could experience as much as a 2.6-GW capacity deficit below the 2023 planning reserve margin requirement. The 2022 survey showed possible capacity deficits thereafter of 4.4 GW in the 2024/25 planning year, 6.5 GW in 2025/26, 7.4 GW in 2026/27 and nearly 11 GW by 2027/28. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)

While last year’s results were affected by MISO’s 1.2-GW capacity deficit across all Midwestern local resource zones, this year’s survey results were influenced by the fact that all zones were resource-adequate starting June 1 and through May 30, 2024, according to the spring capacity auction. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

“With so many moving pieces involved with the changing electricity mix, regional assessments such as this one are becoming increasingly important to fully understand how the region will maintain reliable and affordable electricity delivery to customers,” Organization of MISO States President and Michigan Public Service Commission Chair Dan Scripps said in the release. “The increased transparency that comes with the seasonal granularity of this survey will undoubtably prove useful to state commissions, utilities and other market participants as they look to firm up their future resource plans to provide reliable and affordable electricity.”

MISO said this year’s survey reflected actions market participants took since becoming aware of the capacity deficit in the 2022/23 planning year, which included delaying unit retirements and making additional capacity available to the footprint. However, the grid operator warned that “these actions may not be repeatable in the future. It said the survey once again “highlights the need for additional resources and other solutions — such as market changes — to avoid potential capacity deficits in the future.”

During a Friday stakeholder teleconference to discuss results, Scripps stressed that the survey isn’t a carved-in-stone future, but an “aggregation of all the information that is available to us today.” He said it was “undeniable” that market participants’ reactions to last year’s shortfall moved capacity projections from in the red to black for the coming year.

“That said, this is a one-year response,” Scripps said, adding that the temporary remedies are not a substitute for long-term solutions for increasingly scarce capacity.

On the same call, Senior Resource Adequacy Engineer Nick Przybilla said MISO’s supply picture could improve if MISO makes headway on ushering projects through its interconnection queue faster, if supply chain snarls improve and if future planning reserve margins turn up lower than expected.

MISO also cautioned that “resource accreditation will continue to evolve based on performance during high-risk periods.” MISO is resolved to adopt a new marginal capacity accreditation style that values availability during forecasted hazardous periods and stands to lower many resources’ capacity values. (See MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours.)

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Do Batteries or Transmission Produce Greater Benefits?

Adding battery storage to wind and solar resources increased generator revenues more than expanding transmission, especially in CAISO and ERCOT, but transmission expansion could relieve congestion in rural areas with plentiful wind and solar capacity, a recent study by the Lawrence Berkeley National Laboratory found.

The first-of-its-kind study assessed the benefits and drawbacks of transmission expansion and adding batteries to renewables in areas with transmission congestion. It looked at the findings from the perspectives of grid operators and generation owners.

“Both storage and transmission can increase grid flexibility, which is critical to the task of balancing system demand with uncertain variable renewable energy supply in real time, though they engage in different types of arbitrage,” the authors wrote.

“Storage shifts energy over time,” they noted. Optimally, batteries charge when electricity is cheap and discharge when prices rise. “Transmission shifts energy from one place to another,” moving lower-cost electricity to where it is needed to meet demand.

“Congestion occurs when transmission limits are reached and prevents low-cost resources from being fully utilized,” the study said. “Even [renewable energy resources], which have extremely low marginal costs of generation, curtail their output due to negative prices in some locations.”

Renewable resources and storage each affect transmission value, and “transmission capacity affects the commercial viability of generation and storage projects,” the study said. “So, understanding the dynamics of interplay between these asset types is essential to effectively plan for the changing grid.”

That is especially important because renewable generation and storage “are increasingly being built at the same locations in hybrid configurations,” it said.

For example, in CAISO, 99% of solar capacity entering the interconnection queue in 2021 was coupled with storage, it noted.

“These changes raise critical questions such as, ‘Will the shift towards hybrid plant deployment reduce congestion on the nearby transmission grid or will the shift necessitate additional actions to alleviate congestion?’” it said.

‘VRE-rich’ Areas

The study analyzed data from 23 locations on the U.S. bulk power system that experience significant congestion and have standalone solar and wind plants. The locations were in CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM and SPP.

The findings from a grid operator’s perspective include:

    • Standalone wind and solar generators typically alleviate congestion near urban load centers and exacerbate congestion in rural areas with a high number of variable renewable energy (VRE) generators, which the study calls “VRE-rich” areas.
    • Standalone storage plants reduce transmission congestion in all areas.
    • Hybrid resources with renewable generation and storage alleviate congestion near load centers, but in VRE-rich areas, they can have different effects depending on their exact location and factors, such as whether batteries can charge from the grid.

For generation owners, the study found that:

    • Transmission expansion is generally a financial detriment to standalone wind and solar plants in load centers and a benefit to those in VRE-rich areas.
    • For hybrid resources in VRE-rich areas, expanding transmission typically increases revenue, but there are exceptions.
    • In VRE-rich areas, wind plants stand to gain “significantly more from transmission expansion,” while solar plants would benefit more from adding batteries.

“Solar plants in VRE-rich areas [could] expect to benefit from transmission expansion, but this benefit is dwarfed by the potential opportunity from installing storage, especially in CAISO and ERCOT, suggesting solar developers would be more invested in policies promoting hybridization than those focused on transmission,” the study said.

The solar plants in the study with the greatest per-MW revenue increase were in ERCOT ($200,000 to $380,000/MW-year) and CAISO ($50,000 to $91,000/MW-year) — both markets with a large share of solar generation.

The study’s authors said the results highlight the “different stakes that solar and wind developers have in local transmission expansion and how their priorities depend on a plant’s location and configuration.”

The results also “reveal previously unexplored ways in which policy, technology and contract terms related to hybrids can reduce the cost of congestion in local transmission systems,” the study said. “For example, policies incentivizing batteries at congested generation nodes may reduce congestion, since building storage alongside new VRE generators (either in hybrid or standalone configurations) is better, from a congestion perspective, than the standalone generator.

“Further, policies that allow hybrids to charge their storage component from the grid, instead of only from the VRE generator, result in lower costs due to congestion.”

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ERCOT Sets New Demand Mark, Will be Short-lived

ERCOT appears to have set another peak demand record on Monday, but if the grid operator’s projections hold out, the mark will be short-lived.

Demand averaged 81.56 GW on Monday during the interval ending at 5 p.m., according to preliminary data. That would break ERCOT’s current unofficial high for demand, when it averaged 81.41 GW July 13.

The grid operator’s six-day forecast indicates it will exceed 86 GW Tuesday, with average demand exceeding 83 GW through Friday. A high-pressure ridge and expanding heat dome have returned to the region and the southern U.S., diverting the jet stream away. Temperatures were forecast to be 5 to 15 degrees Fahrenheit above normal in much of Texas as excessive-heat advisories affect more than 100 million people from Washington state to Florida.

ERCOT says it expects to have sufficient generation to meet forecasted demand. It hasn’t called for voluntary conservation since June 20 and had more than 6.6 GW of operating reserves Monday afternoon. It did issue its third weather watch of the summer for Sunday through Tuesday due to the forecasted temperatures, electrical demand and potential for lower reserves.

The grid operator has averaged more than 80 GW demand for 18 intervals this summer. It reached the mark just once last year, setting a record that has been eclipsed 14 times already.

The clear skies again have led to near-record solar and renewable generation. Sun-powered resources averaged more than 12 GW for much of the afternoon; together with wind resources, they provided more than a third of ERCOT’s fuel mix for much of the day.

The U.S. Energy Information Administration says ERCOT’s solar and wind capacity will double by 2035, but it noted that without upgrades to the transmission system, its analysis finds wind and solar generation increasingly will be curtailed.

ERCOT had almost 10 GW of thermal outages on July 12. Staff use 8.3 GW as a high number in their modeling scenarios.

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MISO Monitor Again Sounds Alarm on Long-range Tx Planning

CARMEL, Ind. — MISO Independent Market Monitor David Patton appeared at this week’s Market Subcommittee meeting to again criticize the future resource mix assumptions the RTO is using to craft a second long-range transmission plan (LRTP) for its Midwest region.

Stakeholder reactions to his advice were mixed.

Patton has voiced concerns in this year’s State of the Market report over the capacity expansion model MISO is using to inform the portfolio, which could run the region several billion dollars. He said MISO isn’t considering enough future battery storage, hybrid resources, other dispatchable resource additions and grid-enhancing technologies as alternatives to an expensive transmission buildout. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

At the MSC’s meeting Thursday, Patton said battery storage is going to become “remarkably economic over time to reduce congestion caused by renewables.” He said MISO’s second transmission planning future’s projection that it will have 466 GW of mostly renewable nameplate capacity by 2042 is unrealistic. (See MISO Modeling Line Options for 2nd LRTP Portfolio.) MISO is anticipating having 31 GW of battery storage and 10 GW of storage-plus-renewable hybrid resources in that timeframe.

“Future 2 has almost no chance of happening, and yet we’re using it to plan tranche 2” of the LRTP, Patton said.

This is the first time Patton has raised concerns related to transmission planning in his report. MISO’s Board of Directors has wondered whether it’s appropriate for the Monitor to recommend a change in direction on transmission planning. Patton has argued that markets and transmission planning are inextricably linked.

American Transmission Co.’s Bob McKee and ITC Holdings’ Brian Drumm said Future 2 represents years of stakeholder debate and collaboration.

McKee asked whether Patton attended the stakeholder meetings to hash out the future planning assumptions. Patton said he “unfortunately” did not and wish he had.

“I’m all for consensus, but you can’t confuse consensus with fact. You can’t ignore that solar will have declining capacity value, and you can’t just imagine you’re going to keep building it and building it,” Patton said.

Michelle Bloodworth, of coal lobby group America’s Power, said she shared Patton’s concerns and that the second future should contemplate a realistic future resource mix.

Invenergy’s Sophia Dossin asked whether Patton has suggestions on how MISO can incent construction on batteries and hybrid resources.

Patton said the simple economics of MISO’s more attractive capacity accreditation for batteries, hybrid resources and natural gas plants will spur developers to build. He added that he isn’t expecting future bans on building new gas plants in every state in the footprint.

MISO will make a formal response to the recommendations in this year’s State of the Market report in December.

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Nevada Exits US Climate Alliance

Gov. Joe Lombardo has removed Nevada from the U.S. Climate Alliance, saying the group’s objectives conflict with his goal of developing a diverse energy portfolio for the state that includes natural gas.

The decision came to light as Arizona Gov. Katie Hobbs announced this week that the Grand Canyon State had joined the Alliance. Lombardo made no official announcement of Nevada’s exit from the Alliance, but Nevada’s absence from the group’s membership roster was noticed following Hobbs’ announcement.

“While the goals of the U.S. Climate Alliance are ambitious and well-intentioned, these goals conflict with Nevada’s energy policy objectives,” Lombardo said in a July 5 letter to U.S. Climate Alliance Executive Director Casey Katims, stating his decision to leave the coalition.

“These objectives are focused on developing and maintaining a diverse energy supply portfolio and utilizing a balanced approach to electric and natural gas energy supply and transportation fuels that emphasizes affordability and reliability for consumers,” Lombardo wrote.

Lombardo laid out his energy policies in a March executive order, including the state’s “advancement of energy independence.” (See New Governor Seeks Shift in Nevada Energy Policy.)

Nevada’s previous governor, Steve Sisolak, brought the state into the Alliance in 2019. Sisolak, a Democrat, was defeated in his reelection bid last year by Lombardo, a Republican.

Lombardo’s office didn’t respond to a request for comment.

Falling Short of GHG Targets

Formed in 2017, the U.S. Climate Alliance is now a bipartisan coalition with 25 members. Alliance members have agreed to work toward the Paris Agreement goal of keeping global temperature rise at less than 1.5 degrees Celsius. They collectively set a target to reduce greenhouse gas emissions by at least 26% by 2025 and 50% by 2030, compared with 2005 levels, and reaching net zero in 2050.

The GHG reduction goals are similar to those included in Nevada’s greenhouse gas inventory, an annual report required by state Senate Bill 254 of 2019.

The most recent GHG report, released this year, shows Nevada slipping further from those targets. The report details the state’s GHG emissions through 2020, with projections through 2042.

Nevada’s targets used as a benchmark in the report are a 28% reduction in GHG emissions by 2025 relative to 2005 levels; a 45% reduction by 2030; and zero or near-zero emissions by 2050. But the report projects only a 21.4% reduction in GHG emissions by 2025 and a 22.7% reduction by 2030.

And those reductions are slightly less than projections in the state’s GHG inventory from a year earlier, which forecast a 22.5% reduction in GHG emissions by 2025 and a 23.9% reduction by 2030.

In 2020, Nevada’s net GHG emissions totaled 37.3 million metric tons of CO2 equivalent, a 24.4% reduction from 2005 levels. GHG emissions in 2020 were less than the 2019 levels of 40.6 million metric tons. The report attributes the 2020 decrease to impacts of the COVID-19 pandemic, particularly on the transportation sector.

The transportation sector was the largest contributor to GHG emissions in Nevada, accounting for 32% of gross emissions in 2020, followed by electricity generation, which accounted for 31%.

For projecting future GHG emissions, the report makes several assumptions, including future retirements of natural gas-fired electric generating units. But the Public Utilities Commission of Nevada this year approved NV Energy’s request to postpone retirements of several gas-fired plants, as well as construction of a new 400-MW gas-fired peaker plant. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.)

Next year’s GHG inventory will likely factor in the recent PUCN decisions.

‘Door is Open’

Evan Westrup, communications director for the U.S. Climate Alliance, said Lombardo’s decision to leave the Alliance was disappointing, but “our door is open” if he changes his mind.

“As unprecedented wildfire smoke, record heat and catastrophic floods sweep across the country, we need every state and every governor — no matter their politics — confronting this crisis,” Westrup said in an email.

Westrup noted that newly elected governors in other Alliance states have opted to remain in the coalition, including the governors of Massachusetts, Hawaii, Oregon, Maryland and Pennsylvania.

Christi Cabrera-Georgeson, co-deputy director of the Nevada Conservation League, credited Lombardo for signing bills this year that will create more accountability and transparency in utility planning and promote clean energy.

But Lombardo’s decision to leave the U.S. Climate Alliance “contradicts these efforts and cedes Nevada’s leadership on clean energy and climate,” she said.

“This was a choice to prioritize utilities and their profits over everyday Nevadans who are already struggling to pay their energy bills amid record-breaking temperatures,” Cabrera-Georgeson said in an email. “By not prioritizing clean energy investments to diversify our job market and reduce greenhouse gas emissions, Nevada’s economy and environment will also suffer.”

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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.